EXHIBIT
99.1
 
 
 INDEX TO FINANCIAL
STATEMENTS
 
 Energy Transfer Equity, L.P.
and Subsidiaries
 
 
 PageReport
      of Independent Registered Public Accounting Firm
              2Consolidated
      Balance Sheets – December 31, 2009 and 2008
              3Consolidated
      Statements of Operations – Years Ended December 31, 2009 and
      2008,Four
      Months Ended December 31, 2007 and Year Ended August 31,
    2007
              5Consolidated
      Statements of Comprehensive Income – Years Ended December 31, 2009 and
      2008,Four
      Months Ended December 31, 2007 and Year Ended August 31,
    2007
              6Consolidated
      Statements of Equity –Years
      Ended December 31, 2009 and 2008, Four Months Ended December 31, 2007 and
      Year Ended August 31, 2007
              7Consolidated
      Statements of Cash Flows – Years Ended December 31, 2009 and
      2008,Four
      Months Ended December 31, 2007 and Year Ended August 31,
    2007
              8Notes
      to Consolidated Financial Statements
              9
  1
  REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 
 Partners
 Energy
Transfer Equity, L.P.
 
 We have
audited the accompanying consolidated balance sheets of Energy Transfer Equity,
L.P. (a Delaware limited partnership) and subsidiaries as of December 31, 2009
and 2008, and the related consolidated statements of operations, comprehensive
income, equity, and cash flows for each of the two years in the period ended
December 31, 2009, the four months ended December 31, 2007, and the year ended
August 31, 2007. These financial statements are the responsibility of the
Partnership's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
 
 We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
 
 In our
opinion, the consolidated financial statements referred to above present fairly,
in all material respects, the financial position of Energy Transfer Equity, L.P.
and subsidiaries as of December 31, 2009 and 2008, and the results of their
operations and their cash flows for each of the two years in the period ended
December 31, 2009, the four months ended December 31, 2007, and the year ended
August 31, 2007 in conformity with accounting principles generally accepted in
the United States of America.
 
 As
discussed in Note 2, the Partnership retrospectively adopted a new accounting
pronouncement on January 1, 2009 related to the accounting for noncontrolling
interests in consolidated financial statements.
 
 We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), Energy Transfer Equity, L.P.’s internal control
over financial reporting as of December 31, 2009, based on criteria established
in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO) and our report dated February 24, 2010 (not
separately included herein), expressed an unqualified opinion on the
effectiveness of internal control over financial reporting.
 
 
 /s/ GRANT
THORNTON LLP
 
 
 Tulsa,
Oklahoma
 February
24, 2010
  2
  ENERGY TRANSFER EQUITY, L.P.
AND SUBSIDIARIES
 
 CONSOLIDATED BALANCE
SHEETS
 (Dollars
in thousands)
 
 December 31,
                2009
              
              
              December 31,
                2008ASSETSCURRENT
      ASSETS:Cash
      and cash equivalents
              
              $
              68,315
              
              
              $
              92,023Marketable
      securities
              
              
              6,055
              
              
              
              5,915Accounts
      receivable, net of allowance for doubtful accounts
              
              
              566,522
              
              
              
              591,257Accounts
      receivable from related companies
              
              
              51,894
              
              
              
              15,142Inventories
              
              
              389,954
              
              
              
              272,348Exchanges
      receivable
              
              
              23,136
              
              
              
              45,209Price
      risk management assets
              
              
              12,371
              
              
              
              5,423Other
      current assets
              
              
              149,712
              
              
              
              153,678Total
      current assets
              
              
              1,267,959
              
              
              
              1,180,995PROPERTY,
      PLANT AND EQUIPMENT, net
              
              
              9,064,475
              
              
              
              8,702,534ADVANCES
      TO AND INVESTMENT IN AFFILIATES
              
              
              663,298
              
              
              
              10,110GOODWILL
              
              
              775,094
              
              
              
              773,283INTANGIBLES
      AND OTHER ASSETS, net
              
              
              389,683
              
              
              
              402,980Total
      assets
              
              $
              12,160,509
              
              
              $
              11,069,902
 
 The
accompanying notes are an integral part of these consolidated financial
statements.
  3
  ENERGY TRANSFER EQUITY, L.P.
AND SUBSIDIARIES
 
 CONSOLIDATED BALANCE
SHEETS
 (Dollars
in thousands)
 
 December 31,
                2009
              
              
              December 31,
                2008LIABILITIES AND EQUITYCURRENT
      LIABILITIES:Accounts
      payable
              
              $
              359,176
              
              
              $
              381,933Accounts
      payable to related companies
              
              
              38,515
              
              
              
              34,495Exchanges
      payable
              
              
              19,203
              
              
              
              54,636Price
      risk management liabilities
              
              
              65,146
              
              
              
              142,432Interest
      payable
              
              
              137,708
              
              
              
              115,487Accrued
      and other current liabilities
              
              
              229,073
              
              
              
              434,706Current
      maturities of long-term debt
              
              
              40,924
              
              
              
              45,232Total
      current liabilities
              
              
              889,745
              
              
              
              1,208,921LONG-TERM
      DEBT,  less current maturities
              
              
              7,750,998
              
              
              
              7,190,357LONG-TERM
      PRICE RISK MANAGEMENT LIABILITIES
              
              
              73,332
              
              
              
              121,710DEFERRED
      INCOME TAXES
              
              
              204,373
              
              
              
              194,871OTHER
      NON-CURRENT LIABILITIES
              
              
              21,810
              
              
              
              14,727COMMITMENTS
      AND CONTINGENCIES (Note 11)8,940,258
              
              
              
              8,730,586EQUITY:PARTNERS’
      CAPITAL (DEFICIT):General
      Partner
              
              
              368
              
              
              
              155Limited
      Partners:Common
      Unitholders (222,898,248 and 222,829,956 units authorized,
                issued and outstanding at December 31, 2009 and 2008,
      respectively)
              
              
              53,412
              
              
              
              (15,762
              )Accumulated
      other comprehensive loss
              
              
              (53,628
              )
              
              
              (67,825
              )Total
      partners’ capital (deficit)
              
              
              152
              
              
              
              (83,432
              )Noncontrolling
      interest
              
              
              3,220,099
              
              
              
              2,422,748Total
      equity
              
              
              3,220,251
              
              
              
              2,339,316Total
      liabilities and equity
              
              $
              12,160,509
              
              
              $
              11,069,902
 
 The
accompanying notes are an integral part of these consolidated financial
statements.
  4
  ENERGY TRANSFER EQUITY, L.P.
AND SUBSIDIARIES
 
 CONSOLIDATED STATEMENTS OF
OPERATIONS
 (Dollars
in thousands, except per unit data)
 
 Years Ended
    December 31,
              
              
              Four
      Months Ended December 31,
              
              
              Year
      Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007REVENUES:Natural
      gas operations
              
              $
              4,115,806
              
              
              $
              7,653,156
              
              
              $
              1,832,192
              
              
              $
              5,385,892Retail
      propane
              
              
              1,190,524
              
              
              
              1,514,599
              
              
              
              471,494
              
              
              
              1,179,073Other
              
              
              110,965
              
              
              
              125,612
              
              
              
              45,656
              
              
              
              227,072Total
      revenues
              
              
              5,417,295
              
              
              
              9,293,367
              
              
              
              2,349,342
              
              
              
              6,792,037COSTS
      AND EXPENSES:Cost
      of products sold - natural gas operations
              
              
              2,519,575
              
              
              
              5,885,982
              
              
              
              1,343,237
              
              
              
              4,207,700Cost
      of products sold - retail propane
              
              
              574,854
              
              
              
              1,014,068
              
              
              
              315,698
              
              
              
              734,204Cost
      of products sold - other
              
              
              27,627
              
              
              
              38,030
              
              
              
              14,719
              
              
              
              136,302Operating
      expenses
              
              
              680,893
              
              
              
              781,831
              
              
              
              221,757
              
              
              
              559,600Depreciation
      and amortization
              
              
              325,024
              
              
              
              274,372
              
              
              
              75,406
              
              
              
              191,383Selling,
      general and administrative
              
              
              178,924
              
              
              
              200,181
              
              
              
              61,874
              
              
              
              153,512Total
      costs and expenses
              
              
              4,306,897
              
              
              
              8,194,464
              
              
              
              2,032,691
              
              
              
              5,982,701OPERATING
      INCOME
              
              
              1,110,398
              
              
              
              1,098,903
              
              
              
              316,651
              
              
              
              809,336OTHER
      INCOME (EXPENSE):Interest
      expense, net of interest capitalized
              
              
              (468,420
              )
              
              
              (357,541
              )
              
              
              (103,375
              )
              
              
              (279,986
              )Equity
      in earnings (losses) of affiliates
              
              
              20,597
              
              
              
              (165
              )
              
              
              (94
              )
              
              
              5,161Gains
      (losses) on disposal of assets
              
              
              (1,564
              )
              
              
              (1,303
              )
              
              
              14,310
              
              
              
              (6,310
              )Gains
      (losses) on non-hedged interest rate derivatives
              
              
              33,619
              
              
              
              (128,423
              )
              
              
              (28,683
              )
              
              
              29,081Allowance
      for equity funds used during construction
              
              
              10,557
              
              
              
              63,976
              
              
              
              7,276
              
              
              
              4,948Other,
      net
              
              
              1,913
              
              
              
              8,115
              
              
              
              (13,327
              )
              
              
              1,129INCOME
      BEFORE INCOME TAX EXPENSE
              
              
              707,100
              
              
              
              683,562
              
              
              
              192,758
              
              
              
              563,359Income
      tax expense
              
              
              9,229
              
              
              
              3,808
              
              
              
              9,949
              
              
              
              11,391NET
      INCOME
              
              
              697,871
              
              
              
              679,754
              
              
              
              182,809
              
              
              
              551,968LESS:
      NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
              
              
              255,398
              
              
              
              304,710
              
              
              
              90,132
              
              
              
              232,608NET
      INCOME ATTRIBUTABLE TO PARTNERS
              
              
              442,473
              
              
              
              375,044
              
              
              
              92,677
              
              
              
              319,360GENERAL
      PARTNER'S INTEREST IN NET INCOME
              
              
              1,370
              
              
              
              1,161
              
              
              
              287
              
              
              
              1,048LIMITED
      PARTNERS' INTEREST IN NET INCOME
              
              $
              441,103
              
              
              $
              373,883
              
              
              $
              92,390
              
              
              $
              318,312BASIC
      NET INCOME PER LIMITED PARTNER UNIT
              
              $
              1.98
              
              
              $
              1.68
              
              
              $
              0.41
              
              
              $
              1.56BASIC
      AVERAGE NUMBER OF UNITS OUTSTANDING
              
              
              222,898,203
              
              
              
              222,829,956
              
              
              
              222,829,916
              
              
              
              204,578,719DILUTED
      NET INCOME PER LIMITED PARTNER UNIT
              
              $
              1.98
              
              
              $
              1.68
              
              
              $
              0.41
              
              
              $
              1.55DILUTED
      AVERAGE NUMBER OF UNITS  OUTSTANDING
              
              
              222,898,203
              
              
              
              222,829,956
              
              
              
              222,829,916
              
              
              
              204,578,719
 
 The
accompanying notes are an integral part of these consolidated financial
statements.
  5
  ENERGY TRANSFER EQUITY, L.P.
AND SUBSIDIARIES
 
 CONSOLIDATED STATEMENTS OF
COMPREHENSIVE INCOME
 (Dollars
in thousands)
 
 Years Ended December 31,
              
              
              Four
      Months Ended December 31,
              
              
              Year
      Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Net
      income
              
              $
              697,871
              
              
              $
              679,754
              
              
              $
              182,809
              
              
              $
              551,968Other
      comprehensive income (loss), net of tax:Reclassification
      to earnings of gains and losses on derivative instruments accounted for as
      cash flow hedges
              
              
              16,958
              
              
              
              (22,916
              )
              
              
              (17,970
              )
              
              
              (163,378
              )Change
      in value of derivative instruments accounted for as cash flow
      hedges
              
              
              (11,017
              )
              
              
              (40,350
              )
              
              
              (2,221
              )
              
              
              179,861Change
      in value of available-for-sale securities
              
              
              10,923
              
              
              
              (6,418
              )
              
              
              (98
              )
              
              
              28016,864
              
              
              
              (69,684
              )
              
              
              (20,289
              )
              
              
              16,763Comprehensive
      income
              
              
              714,735
              
              
              
              610,070
              
              
              
              162,520
              
              
              
              568,731Less:
      Comprehensive income attributable to noncontrolling
    interest
              
              
              258,066
              
              
              
              291,624
              
              
              
              92,832
              
              
              
              239,885Comprehensive
      income attributable to partners
              
              $
              456,669
              
              
              $
              318,446
              
              
              $
              69,688
              
              
              $
              328,846
 
 The
accompanying notes are an integral part of these consolidated financial
statements.
  6
  ENERGY TRANSFER EQUITY, L.P.
AND SUBSIDIARIES
 
 CONSOLIDATED STATEMENTS OF
EQUITY
 (Dollars
in thousands)
 
 General
      Partner
              
              
              Common
      Unitholders
              
              
              Class
      B Unitholders
              
              
              Class
      C Unitholders
              
              
              Accumulated
      Other Comprehensive Income
      (Loss)
              
              
              Noncontrolling
      Interest
              
              
              TotalBalance,
      August 31, 2006
              
              $
              (69
              )
              
              $
              (9,586
              )
              
              $
              53,130
              
              
              $
              -
              
              
              $
              2,276
              
              
              $
              1,439,127
              
              
              $
              1,484,878Unit
      issuances
              
              
              -
              
              
              
              372,638
              
              
              
              -
              
              
              
              4,456
              
              
              
              -
              
              
              
              (4,456
              )
              
              
              372,638Equity
      issue costs of Class C Units
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (204
              )
              
              
              -
              
              
              
              -
              
              
              
              (204
              )Assumption
      of related company debt
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (70,500
              )
              
              
              -
              
              
              
              -
              
              
              
              (70,500
              )Distribution
      to partners
              
              
              (955
              )
              
              
              (246,136
              )
              
              
              (1,645
              )
              
              
              (28,261
              )
              
              
              -
              
              
              
              -
              
              
              
              (276,997
              )Subsidiary
      distributions and other
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (252,584
              )
              
              
              (252,584
              )Purchase
      premium on ETP Class G Units
              
              
              -
              
              
              
              (451,150
              )
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              451,150
              
              
              
              -Tax
      effect of remedial income allocation from tax amortization of
      goodwill
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (1,161
              )
              
              
              (1,161
              )Non-cash
      unit-based compensation expense
              
              
              -
              
              
              
              28
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              10,471
              
              
              
              10,499Other
      comprehensive income, net of tax
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              9,486
              
              
              
              7,277
              
              
              
              16,763Net
      income
              
              
              1,048
              
              
              
              260,184
              
              
              
              2,524
              
              
              
              55,604
              
              
              
              -
              
              
              
              232,608
              
              
              
              551,968Conversion
      to Common Units
              
              
              -
              
              
              
              15,104
              
              
              
              (54,009
              )
              
              
              38,905
              
              
              
              -
              
              
              
              -
              
              
              
              -Balance,
      August 31, 2007
              
              
              24
              
              
              
              (58,918
              )
              
              
              -
              
              
              
              -
              
              
              
              11,762
              
              
              
              1,882,432
              
              
              
              1,835,300Distributions
      to partners
              
              
              (270
              )
              
              
              (86,904
              )
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (87,174
              )Subsidiary
      distributions and other
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (63,756
              )
              
              
              (63,756
              )Tax
      effect of remedial income allocation from tax amortization of
      goodwill
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (1,161
              )
              
              
              (1,161
              )Non-cash
      unit-based compensation expense, net of units tendered by employees for
      tax withholdings
              
              
              -
              
              
              
              23
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              7,950
              
              
              
              7,973Non-cash
      executive compensation expense
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              1,167
              
              
              
              1,167Subsidiary
      sale of common units
              
              
              151
              
              
              
              48,781
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              187,355
              
              
              
              236,287Other
      comprehensive loss, net of tax
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (22,989
              )
              
              
              2,700
              
              
              
              (20,289
              )Net
      income
              
              
              287
              
              
              
              92,390
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              90,132
              
              
              
              182,809Balance,
      December 31, 2007
              
              
              192
              
              
              
              (4,628
              )
              
              
              -
              
              
              
              -
              
              
              
              (11,227
              )
              
              
              2,106,819
              
              
              
              2,091,156Distributions
      to partners
              
              
              (1,349
              )
              
              
              (434,519
              )
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (435,868
              )Subsidiary
      distributions
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (319,963
              )
              
              
              (319,963
              )Tax
      effect of remedial income allocation from tax amortization of
      goodwill
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (3,407
              )
              
              
              (3,407
              )Non-cash
      unit-based compensation expense, net of units tendered by employees for
      tax withholdings
              
              
              -
              
              
              
              823
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              19,968
              
              
              
              20,791Non-cash
      executive compensation expense
              
              
              -
              
              
              
              48
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              1,202
              
              
              
              1,250Subsidiary
      sale of common units
              
              
              151
              
              
              
              48,631
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              326,505
              
              
              
              375,287Other
      comprehensive loss, net of tax
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (56,598
              )
              
              
              (13,086
              )
              
              
              (69,684
              )Net
      income
              
              
              1,161
              
              
              
              373,883
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              304,710
              
              
              
              679,754Balance,
      December 31, 2008
              
              
              155
              
              
              
              (15,762
              )
              
              
              -
              
              
              
              -
              
              
              
              (67,825
              )
              
              
              2,422,748
              
              
              
              2,339,316Distributions
      to ETE partners
              
              
              (1,457
              )
              
              
              (469,201
              )
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (470,658
              )Subsidiary
      distributions
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (381,471
              )
              
              
              (381,471
              )Subsidiary
      sale of common units
              
              
              300
              
              
              
              96,696
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              902,680
              
              
              
              999,676Tax
      effect of remedial income allocation from tax amortization of
      goodwill
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (3,762
              )
              
              
              (3,762
              )Non-cash
      unit-based compensation expense, net of units tendered by employees for
      tax withholdings
              
              
              -
              
              
              
              551
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              20,613
              
              
              
              21,164Non-cash
      executive compensation expense
              
              
              -
              
              
              
              25
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              1,225
              
              
              
              1,250Other
      comprehensive loss, net of tax
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              14,197
              
              
              
              2,668
              
              
              
              16,865Net
      income
              
              
              1,370
              
              
              
              441,103
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              255,398
              
              
              
              697,871Balance,
      December 31, 2009
              
              $
              368
              
              
              $
              53,412
              
              
              $
              -
              
              
              $
              -
              
              
              $
              (53,628
              )
              
              $
              3,220,099
              
              
              $
              3,220,251
 
 The
accompanying notes are an integral part of these consolidated financial
statements.
  7
  ENERGY TRANSFER EQUITY, L.P.
AND SUBSIDIARIES
 
 CONSOLIDATED STATEMENTS OF
CASH FLOWS
 (Dollars
in thousands)
 
 Years
      Ended December 31,
              
              
              Four
      Months Ended December 31,
              
              
              Year
      Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007CASH
      FLOWS FROM OPERATING ACTIVITIES:Net
      income
              
              $
              697,871
              
              
              $
              679,754
              
              
              $
              182,809
              
              
              $
              551,968Reconciliation
      of net income to net cash provided by operating
activities:Depreciation
      and amortization
              
              
              325,024
              
              
              
              274,372
              
              
              
              75,406
              
              
              
              191,383Amortization
      of finance costs charged to interest
              
              
              14,954
              
              
              
              10,962
              
              
              
              2,441
              
              
              
              6,691Provision
      for loss on accounts receivable
              
              
              2,992
              
              
              
              8,015
              
              
              
              544
              
              
              
              4,229Goodwill
      impairment
              
              
              -
              
              
              
              11,359
              
              
              
              -
              
              
              
              -Non-cash
      unit-based compensation expense
              
              
              24,583
              
              
              
              24,304
              
              
              
              8,137
              
              
              
              10,499Non-cash
      executive compensation expense
              
              
              1,250
              
              
              
              1,250
              
              
              
              442
              
              
              
              -Deferred
      income taxes
              
              
              8,422
              
              
              
              (8,177
              )
              
              
              37
              
              
              
              (6,939
              )(Gains)
      losses on disposal of assets
              
              
              1,564
              
              
              
              1,303
              
              
              
              (14,310
              )
              
              
              6,310Distribution
      in excess of (less than) earnings of affiliates, net
              
              
              3,224
              
              
              
              5,621
              
              
              
              4,448
              
              
              
              (5,161
              )Other
      non-cash
              
              
              (4,468
              )
              
              
              3,382
              
              
              
              (2,069
              )
              
              
              (760
              )Net
      change in operating assets and liabilities, net of effects of
      acquisitions
              
              
              (351,955
              )
              
              
              131,575
              
              
              
              (49,250
              )
              
              
              248,100Net
      cash provided by operating activities
              
              
              723,461
              
              
              
              1,143,720
              
              
              
              208,635
              
              
              
              1,006,320CASH
      FLOWS FROM INVESTING ACTIVITIES:Net
      cash (paid for) received in acquisitions
              
              
              30,367
              
              
              
              (84,783
              )
              
              
              (337,092
              )
              
              
              (90,695
              )Capital
      expenditures
              
              
              (748,621
              )
              
              
              (2,054,806
              )
              
              
              (651,228
              )
              
              
              (1,107,127
              )Contributions
      in aid of construction costs
              
              
              6,453
              
              
              
              50,050
              
              
              
              3,493
              
              
              
              10,463(Advances
      to) repayments from affiliates
              
              
              (655,500
              )
              
              
              54,534
              
              
              
              (32,594
              )
              
              
              (993,866
              )Proceeds
      from the sale of assets
              
              
              21,545
              
              
              
              19,420
              
              
              
              21,478
              
              
              
              23,135Net
      cash used in investing activities
              
              
              (1,345,756
              )
              
              
              (2,015,585
              )
              
              
              (995,943
              )
              
              
              (2,158,090
              )CASH
      FLOWS FROM FINANCING ACTIVITIES:Proceeds
      from borrowings
              
              
              3,542,612
              
              
              
              6,205,994
              
              
              
              1,742,802
              
              
              
              6,010,633Principal
      payments on debt
              
              
              (3,020,587
              )
              
              
              (4,890,619
              )
              
              
              (1,062,272
              )
              
              
              (4,628,052
              )Net
      proceeds from issuance of Common Units
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              372,434Subsidiary
      equity offerings, net of issue costs
              
              
              936,337
              
              
              
              373,059
              
              
              
              234,887
              
              
              
              -Distributions
      to partners
              
              
              (470,658
              )
              
              
              (435,868
              )
              
              
              (87,174
              )
              
              
              (276,997
              )Debt
      issuance costs
              
              
              (7,646
              )
              
              
              (25,272
              )
              
              
              (211
              )
              
              
              (23,279
              )Distributions
      to noncontrolling interests
              
              
              (381,471
              )
              
              
              (319,963
              )
              
              
              (61,517
              )
              
              
              (251,823
              )Net
      cash provided by financing activities
              
              
              598,587
              
              
              
              907,331
              
              
              
              766,515
              
              
              
              1,202,916INCREASE
      (DECREASE) IN CASH AND CASH EQUIVALENTS
              
              
              (23,708
              )
              
              
              35,466
              
              
              
              (20,793
              )
              
              
              51,146CASH
      AND CASH EQUIVALENTS, beginning of period
              
              
              92,023
              
              
              
              56,557
              
              
              
              77,350
              
              
              
              26,204CASH
      AND CASH EQUIVALENTS, end of period
              
              $
              68,315
              
              
              $
              92,023
              
              
              $
              56,557
              
              
              $
              77,350
 
 The
accompanying notes are an integral part of these consolidated financial
statements.
  8
  ENERGY TRANSFER EQUITY, L.P.
AND SUBSIDIARIES
 
 NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
 (Tabular
dollar amounts in thousands, except per unit data)
 
 
 1.
              OPERATIONS AND
      ORGANIZATION:
 
 Financial
Statement Presentation
 
 The
consolidated financial statements of Energy Transfer Equity, L.P. and
subsidiaries (the “Partnership”, “ETE” or the “Parent Company”) presented herein
for the years ended December 31, 2009 and 2008, the four months ended December
31, 2007 and the year ended August 31, 2007, have been prepared in accordance
with accounting principles generally accepted in the United States of America
(“GAAP”) and pursuant to the rules and regulations of the Securities and
Exchange Commission (“SEC”).  We consolidate all majority-owned
subsidiaries and limited partnerships, which we control as the general partner
or owner of the general partner.  We present equity and net income
attributable to noncontrolling interest for all partially-owned consolidated
subsidiaries.  All significant intercompany transactions and accounts
are eliminated in consolidation.  Management has evaluated subsequent
events through February 24, 2010, the date the financial statements were
issued.
 
 The
consolidated financial statements of the Partnership presented herein include
the results of operations for ETE, ETE’s controlled subsidiary Energy Transfer
Partners, L.P., a publicly-traded master limited partnership (“ETP”), and ETE’s
wholly-owned subsidiaries: Energy Transfer Partners GP, L.P. (“ETP GP”), the
General Partner of ETP, and Energy Transfer Partners, L.L.C. (“ETP LLC”), the
General Partner of ETP GP.  The results of operations for ETP include
its wholly-owned subsidiaries: La Grange Acquisition, L.P., which conducts
business under the assumed name of Energy Transfer Company (“ETC OLP”); Energy
Transfer Interstate Holdings, LLC (“ET Interstate”), the parent company of
Transwestern Pipeline Company, LLC (“Transwestern”) and ETC Midcontinent Express
Pipeline, LLC (“ETC MEP”); ETC Fayetteville Express Pipeline, LLC (“ETC FEP”);
ETC Tiger Pipeline, LLC (“ETC Tiger”); Heritage Operating, L.P. (“HOLP”);
Heritage Holdings, Inc. (“HHI”); and Titan Energy Partners, L.P.
(“Titan”).  The operations of ET Interstate are included since the
date of the Transwestern acquisition on December 1, 2006.  ETC FEP and
ETC Tiger are included since their inception dates on August 27, 2008 and June
20, 2008, respectively.  The operations of all other subsidiaries
listed above are reflected for all periods presented.
 
 We also
own varying undivided interests in certain pipelines.  Ownership of
these pipelines has been structured as an ownership of an undivided interest in
assets, not as an ownership interest in a partnership, limited liability
company, joint venture or other forms of entities.  Each owner
controls marketing and invoices separately, and each owner is responsible for
any loss, damage or injury that may occur to their own customers.  As
a result, we apply proportionate consolidation for our interests in these
entities.
 
 In
November 2007, we changed our fiscal year end to the calendar
year.  Thus, a new fiscal year began on January 1,
2008.  The Partnership completed a four-month transition period that
began September 1, 2007 and ended December 31, 2007 and filed a transition
report on Form 10-Q for that period in February 2008.  The financial
statements contained herein cover the years ended December 31, 2009 and 2008,
the four months ended December 31, 2007, and the year ended August 31,
2007.
 
 We did
not recast the financial data for the prior fiscal periods because the financial
reporting processes in place at that time included certain procedures that were
completed only on a fiscal quarterly basis.  Consequently, to recast
those periods would have been impractical and would not have been
cost-justified.  Such comparability is impacted primarily by weather,
fluctuations in commodity prices, volumes of natural gas sold and transported,
our hedging strategies and the use of financial instruments, trading activities,
basis differences between market hubs and interest rates.  We believe
that the trends indicated by comparison of the results for the years ended
December 31, 2009 and 2008 are substantially similar to what is reflected in the
information for the year ended August 31, 2007.
 
 Certain
prior period amounts have been reclassified to conform to the 2009
presentation.  Other than the reclassifications related to the
adoption of Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in
Consolidated Financial Statements – An Amendment of ARB No. 51,which is
now incorporated into ASC 810-10-65 (see Note 2), these reclassifications had no
impact on net income or total equity.
  9
  Business
Operations
 
 The
Parent Company currently has no separate operating activities apart from those
conducted by the Operating Companies.  The Parent Company’s principal
sources of cash flow are its direct and indirect investments in the Limited
Partner and General Partner interests in ETP.
 
 The
Parent Company’s primary cash requirements are for general and administrative
expenses, debt service requirements and distributions to its
partners.  The Parent Company-only assets and liabilities of ETE are
not available to satisfy the debts and other obligations of ETP and its
consolidated subsidiaries.  In order to fully understand the financial
condition of the Partnership on a stand-alone basis, see Note 17 for stand-alone
financial information apart from that of the consolidated partnership
information included herein.
 
 In order
to simplify the obligations of the Partnership under the laws of several
jurisdictions in which we conduct business, our activities are primarily
conducted through our operating subsidiaries (collectively the “Operating
Companies”) as follows:
 
 ·
              ETC
      OLP, a Texas limited partnership engaged in midstream and intrastate
      transportation and storage natural gas operations.  ETC OLP owns
      and operates, through its wholly and majority-owned subsidiaries, natural
      gas gathering systems, intrastate natural gas pipeline systems and gas
      processing plants and is engaged in the business of purchasing, gathering,
      transporting, processing, and marketing natural gas and NGLs in the states
      of Texas, Louisiana, Arizona, New Mexico, Utah and
      Colorado.  Our intrastate transportation and storage operations
      primarily focus on transporting natural gas through our Oasis pipeline, ET
      Fuel System, East Texas pipeline and HPL System.  Our midstream
      operations focus on the gathering, compression, treating, conditioning and
      processing of natural gas, primarily on or through our Southeast Texas
      System and North Texas System, and marketing activities.  We
      also own and operate natural gas gathering pipelines and conditioning
      facilities in the Piceance-Uinta Basin of Colorado and
    Utah.
 
 ·
              ET
      Interstate, the parent company of Transwestern and ETC MEP, both of which
      are Delaware limited liability companies engaged in interstate
      transportation of natural gas.  Interstate revenues consist
      primarily of fees earned from natural gas transportation services and
      operational gas sales.
 
 ·
              ETC
      Fayetteville Express Pipeline, LLC, a Delaware limited liability company
      formed to engage in interstate transportation of natural
    gas.
 
 ·
              ETC
      Tiger Pipeline, LLC, a Delaware limited liability company formed to engage
      in interstate transportation of natural
gas.
 
 ·
              HOLP,
      a Delaware limited partnership primarily engaged in retail propane
      operations.  Our retail propane operations focus on sales of
      propane and propane-related products and services.  The retail
      propane customer base includes residential, commercial, industrial and
      agricultural customers.
 
 ·
              Titan,
      a Delaware limited partnership also engaged in retail propane
      operations.
 
 The
Partnership, the Operating Companies and their subsidiaries are collectively
referred to in this report as “we”, “us”, “ETE”, “ETP”, “Energy Transfer” or the
“Partnership.”  References to “the Parent Company” shall mean Energy
Transfer Equity, L.P. on a stand-alone basis.
 
 ETC OLP
owns an interest in and operates approximately 14,800 miles of in service
natural gas gathering and intrastate transportation pipelines, three natural gas
processing plants, eleven natural gas treating facilities, eleven natural gas
conditioning facilities and three natural gas storage facilities located in
Texas.
 
 Revenue
in our intrastate transportation and storage operations is typically generated
from fees charged to customers to reserve firm capacity on or move gas through
the pipeline.  A monetary fee and/or fuel retention are also
components of the fee structure.  Excess fuel retained after
consumption is typically valued at the first of the month published market
prices and strategically sold when market prices are high.  The
intrastate transportation and storage operations also consist of the HPL System,
which generates revenue primarily from the sale of natural gas to electric
utilities, independent power plants, local distribution companies, industrial
end-users and other marketing companies.  The HPL System also
transports natural gas for a variety of third party customers.  Our
intrastate transportation and storage segment also generates revenues from fees
charged for storing customers’ working natural gas in our storage
facilities.  In addition, the use of the Bammel storage facility
allows us to purchase physical natural gas and then sell financial contracts at
a price sufficient to cover its carrying costs and provide a gross profit
margin.
  10
  Our
interstate transportation operations principally focus on natural gas
transportation of Transwestern, which owns and operates approximately 2,700
miles of interstate natural gas pipeline, with an additional 180 miles under
construction, extending from Texas through the San Juan Basin to the California
border.  In addition, we have interests in joint ventures that have
500 miles of interstate natural gas pipeline and 185 miles under
construction.  Transwestern is a major natural gas transporter to the
California border and delivers natural gas from the east end of its system to
Texas intrastate and Midwest markets.  The Transwestern pipeline
interconnects with our existing intrastate pipelines in West
Texas.  The revenues of this segment consist primarily of fees earned
from natural gas transportation services and operational gas sales.
 
 Revenue
in our midstream operations is primarily generated by the volumes of natural gas
gathered, compressed, treated, processed, purchased and sold through our
pipelines (excluding the interstate transportation pipelines) and gathering
systems as well as the level of natural gas and NGL prices.
 
 Our
retail propane segment sells propane and propane-related products and
services.  The HOLP and Titan customer base includes residential,
commercial, industrial and agricultural customers.
 
 2.
              ESTIMATES,SIGNIFICANT ACCOUNTING
      POLICIES AND BALANCE SHEET
DETAIL:
 
 Use
of Estimates
 
 The
preparation of financial statements in conformity with GAAP requires management
to make estimates and assumptions that affect the reported amounts of assets and
liabilities and the accrual for and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period.
 
 The
natural gas industry conducts its business by processing actual transactions at
the end of the month following the month of delivery.  Consequently,
the most current month’s financial results for the midstream and intrastate
transportation and storage segments are estimated using volume estimates and
market prices.  Any differences between estimated results and actual
results are recognized in the following month’s financial
statements.  Management believes that the operating results estimated
for the year ended December 31, 2009 represent the actual results in all
material respects.
 
 Some of
the other significant estimates made by management include, but are not limited
to, the timing of certain forecasted transactions that are hedged, allowances
for doubtful accounts, the fair value of derivative instruments, useful lives
for depreciation and amortization, purchase accounting allocations and
subsequent realizability of intangible assets, fair value measurements used in
the goodwill impairment test, market value of inventory, estimates related to
our unit-based compensation plans, deferred taxes, assets and liabilities
resulting from the regulated ratemaking process, contingency reserves and
environmental reserves.  Actual results could differ from those
estimates.
 
 Revenue
Recognition
 
 Revenues
for sales of natural gas, NGLs including propane, and propane appliances, parts,
and fittings are recognized at the later of the time of delivery of the product
to the customer or the time of sale or installation.  Revenues from
service labor, transportation, treating, compression and gas processing, are
recognized upon completion of the service.  Transportation capacity
payments are recognized when earned in the period the capacity is made
available.  Tank rent is recognized ratably over the period it is
earned.
 
 Our
intrastate transportation and storage and interstate transportation segments’
results are determined primarily by the amount of capacity our customers reserve
as well as the actual volume of natural gas that flows through the
transportation pipelines.  Under transportation contracts, our
customers are charged (i) a demand fee, which is a fixed fee for the reservation
of an agreed amount of capacity on the transportation pipeline for a specified
period of time and which obligates the customer to pay even if the customer does
not transport natural gas on the respective pipeline, (ii) a transportation fee,
which is based on the actual throughput of natural gas by the customer, (iii) a
fuel retention based on a percentage of gas transported on the pipeline, or (iv)
a combination of the three, generally payable monthly.
  11
  Our
intrastate transportation and storage segment also generates revenues and margin
from the sale of natural gas to electric utilities, independent power plants,
local distribution companies, industrial end-users and other marketing companies
on the HPL System.  Generally, we purchase natural gas from the
market, including purchases from the midstream segment’s marketing operations,
and from producers at the wellhead.
 
 In
addition, our intrastate transportation and storage segment generates revenues
and margin from fees charged for storing customers’ working natural gas in our
storage facilities.  We also engage in natural gas storage
transactions in which we seek to find and profit from pricing differences that
occur over time utilizing the Bammel storage reservoir.  We purchase
physical natural gas and then sell financial contracts at a price sufficient to
cover our carrying costs and provide for a gross profit margin.  We
expect margins from natural gas storage transactions to be higher during the
periods from November to March of each year and lower during the period from
April through October of each year due to the increased demand for natural gas
during colder weather.  However, we cannot assure that management’s
expectations will be fully realized in the future and in what time period, due
to various factors including weather, availability of natural gas in regions in
which we operate, competitive factors in the energy industry, and other
issues.
 
 Results
from the midstream segment are determined primarily by the volumes of natural
gas gathered, compressed, treated, processed, purchased and sold through our
pipeline and gathering systems and the level of natural gas and NGL
prices.  We generate midstream revenues and gross margins principally
under fee-based or other arrangements in which we receive a fee for natural gas
gathering, compressing, treating or processing services.  The revenue
earned from these arrangements is directly related to the volume of natural gas
that flows through our systems and is not directly dependent on commodity
prices.
 
 We also
utilize other types of arrangements in our midstream segment, including (i)
discount-to-index price arrangements, which involve purchases of natural gas at
either (1) a percentage discount to a specified index price, (2) a specified
index price less a fixed amount or (3) a percentage discount to a specified
index price less an additional fixed amount, (ii) percentage-of-proceeds
arrangements under which we gather and process natural gas on behalf of
producers, sell the resulting residue gas and NGL volumes at market prices and
remit to producers an agreed upon percentage of the proceeds based on an index
price, and (iii) keep-whole arrangements where we gather natural gas from the
producer, process the natural gas and sell the resulting NGLs to third parties
at market prices.  In many cases, we provide services under contracts
that contain a combination of more than one of the arrangements described
above.  The terms of our contracts vary based on gas quality
conditions, the competitive environment at the time the contracts are signed and
customer requirements.  Our contract mix may change as a result of
changes in producer preferences, expansion in regions where some types of
contracts are more common and other market factors.
 
 We
conduct marketing activities in which we market the natural gas that flows
through our assets, referred to as on-system gas.  We also attract
other customers by marketing volumes of natural gas that do not move through our
assets, referred to as off-system gas.  For both on-system and
off-system gas, we purchase natural gas from natural gas producers and other
supply points and sell that natural gas to utilities, industrial consumers,
other marketers and pipeline companies, thereby generating gross margins based
upon the difference between the purchase and resale prices.
 
 We have a
risk management policy that provides for oversight over our marketing
activities.  These activities are monitored independently by our risk
management function and must take place within predefined limits and
authorizations.  As a result of our use of derivative financial
instruments that may not qualify for hedge accounting, the degree of earnings
volatility that can occur may be significant, favorably or unfavorably, from
period to period.  We attempt to manage this volatility through the
use of daily position and profit and loss reports provided to senior management
and predefined limits and authorizations set forth in our risk management
policy.
 
 Regulatory
Accounting - Regulatory Assets and Liabilities
 
 Transwestern,
part of our interstate transportation segment, is subject to regulation by
certain state and federal authorities and has accounting policies that conform
to Statement of Financial Accounting Standards No. 71 (As Amended), Accounting for the Effects of
Certain Types of Regulation, now incorporated into ASC 980, which is in
accordance with the accounting requirements and ratemaking practices of the
regulatory authorities.  The application of these accounting policies
allows us to defer expenses and revenues on the balance sheet as regulatory
assets and liabilities when it is probable that those expenses and revenues will
be allowed in the ratemaking process in a period different from the period in
which they would have been reflected in the consolidated statement of operations
by an unregulated company.  These deferred assets and liabilities will
be reported in results of operations in the period in which the same amounts are
included in rates and recovered from or refunded to
customers.  Management’s assessment of the probability of recovery or
pass through of regulatory assets and liabilities will require judgment and
interpretation of laws and regulatory commission orders.  If, for any
reason, we cease to meet the criteria for application of regulatory accounting
treatment for all or part of our operations, the regulatory assets and
liabilities related to those portions ceasing to meet such criteria would be
eliminated from the consolidated balance sheet for the period in which the
discontinuance of regulatory accounting treatment occurs.
  12
  Cash,
Cash Equivalents and Supplemental Cash Flow Information
 
 Cash and
cash equivalents include all cash on hand, demand deposits, and investments with
original maturities of three months or less.  We consider cash
equivalents to include short-term, highly liquid investments that are readily
convertible to known amounts of cash and which are subject to an insignificant
risk of changes in value.
 
 We place
our cash deposits and temporary cash investments with high credit quality
financial institutions.  At times, our cash and cash equivalents may
be uninsured or in deposit accounts that exceed the Federal Deposit Insurance
Corporation insurance limit.
 
 As a
result of our acquisition of a natural gas compression equipment business in
exchange for ETP Common Units, cash acquired in connection with acquisitions
during 2009 exceeded the cash we paid by $30.4 million.
 
 The net
change in operating assets and liabilities (net of acquisitions) included in
cash flows from operating activities is comprised as follows:
 
 Years Ended
    December 31,
              
              
              Four
      Months Ended December 31,
              
              
              Year
      Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Accounts
      receivable
              
              $
              28,431
              
              
              $
              220,635
              
              
              $
              (169,263
              )
              
              $
              54,347Accounts
      receivable from related companies
              
              
              (26,321
              )
              
              
              3,234
              
              
              
              (12,091
              )
              
              
              (5,376
              )Inventories
              
              
              (101,592
              )
              
              
              96,145
              
              
              
              (168,430
              )
              
              
              196,173Exchanges
      receivable
              
              
              22,074
              
              
              
              (7,888
              )
              
              
              (4,216
              )
              
              
              (3,406
              )Other
      current assets
              
              
              8,195
              
              
              
              (57,150
              )
              
              
              (4,459
              )
              
              
              53,591Intangibles
      and other assets
              
              
              (4,786
              )
              
              
              (40,753
              )
              
              
              605
              
              
              
              (1,817
              )Accounts
      payable
              
              
              (16,024
              )
              
              
              (296,185
              )
              
              
              195,574
              
              
              
              (92,296
              )Accounts
      payable to related companies
              
              
              4,184
              
              
              
              (13,538
              )
              
              
              28,876
              
              
              
              18,560Exchanges
      payable
              
              
              (35,433
              )
              
              
              14,254
              
              
              
              6,117
              
              
              
              3,000Accrued
      and other current liabilities
              
              
              (124,147
              )
              
              
              32,474
              
              
              
              1,026
              
              
              
              (26,794
              )Interest
      payable
              
              
              22,220
              
              
              
              36,501
              
              
              
              41,640
              
              
              
              18,181Other
      long-term liabilities
              
              
              1,401
              
              
              
              1,741
              
              
              
              (680
              )
              
              
              1,460Price
      risk management liabilities, net
              
              
              (130,157
              )
              
              
              142,105
              
              
              
              36,051
              
              
              
              32,477Net
      change in assets and liabilities, net of effect of
      acquisitions
              
              $
              (351,955
              )
              
              $
              131,575
              
              
              $
              (49,250
              )
              
              $
              248,100
  13
  Non-cash
investing and financing activities and supplemental cash flow information are as
follows:
 
 Years Ended
    December 31,
              
              
              Four
      Months Ended December 31,
              
              
              Year
      Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007NON-CASH
      INVESTING ACTIVITIES:Transfer
      of investment in affiliate in purchase of Transwestern (Note
      3)
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              956,348Investment
      in Calpine Corporation received in exchange for accounts
      receivable
              
              $
              -
              
              
              $
              10,816
              
              
              $
              -
              
              
              $
              -Capital
      expenditures accrued
              
              $
              46,134
              
              
              $
              153,230
              
              
              $
              87,622
              
              
              $
              43,498Gain
      from subsidiary issuance of common units (recorded in partners'
      capital)
              
              $
              96,996
              
              
              $
              48,782
              
              
              $
              48,932
              
              
              $
              -NON-CASH
      FINANCING ACTIVITIES:Long-term
      debt assumed and non-compete agreement notes payable issued in
      acquisitions
              
              $
              26,237
              
              
              $
              5,077
              
              
              $
              3,896
              
              
              $
              533,625Subsidiary
      issuance of Common Units in connection with certain
      acquisitions
              
              $
              63,339
              
              
              $
              2,228
              
              
              $
              1,400
              
              
              $
              -SUPPLEMENTAL
      CASH FLOW INFORMATION:Cash
      paid for interest, net of interest capitalized
              
              $
              440,492
              
              
              $
              330,816
              
              
              $
              79,084
              
              
              $
              283,854Cash
      paid for income taxes
              
              $
              15,447
              
              
              $
              5,191
              
              
              $
              9,135
              
              
              $
              8,962
 
 Marketable
Securities
 
 Marketable
securities are classified as available-for-sale securities and are reflected as
current assets on the consolidated balance sheets at fair value.
 
 During the year ended
December 31, 2008, we determined there was an other-than-temporary decline in
the market value of one of our available-for-sale securities, and reclassified
into earnings a loss of $1.4 million, which is recorded in other
expense.  Unrealized holding gains (losses), net of tax, of $7.4
million, $(6.4) million, $(0.1) million and $0.3 million, were recorded through
accumulated other comprehensive income (“AOCI”), based on the market value of
the securities, for the years ended December 31, 2009 and 2008, the four months
ended December 31, 2007, and the fiscal year ended August 31, 2007,
respectively.  The change in value of our available-for-sale
securities for the year ended December 31, 2009 includes realized losses of $3.5
million reclassified from AOCI during the period as discussed in “Accounts
Receivable” below.
 
 Accounts
Receivable
 
 Our
midstream and intrastate transportation and storage operations deal with
counterparties that are typically either investment grade or are otherwise
secured with a letter of credit or other form of security (corporate guaranty
prepayment or master setoff agreement).  Management reviews midstream
and intrastate transportation and storage accounts receivable balances
bi-weekly.  Credit limits are assigned and monitored for all
counterparties of the midstream and intrastate transportation and storage
operations.  Bad debt expense related to these receivables is
recognized at the time an account is deemed uncollectible.  Management
believes that the occurrence of bad debt in our midstream and intrastate
transportation and storage segments was not significant at December 31, 2009 or
2008; therefore, an allowance for doubtful accounts for the midstream and
intrastate transportation and storage segments was not deemed
necessary.
 
 ETP’s
interstate transportation operations have a concentration of customers in the
electric and gas utility industries as well as natural gas
producers.  This concentration of customers may impact our overall
exposure to credit risk, either positively or negatively, in that the customers
may be similarly affected by changes in economic or other
conditions.  From time to time, specifically identified customers
having perceived credit risk are required to provide prepayments or other forms
of collateral.  Transwestern’s management believes that the portfolio
of receivables, which includes regulated electric utilities, regulated local
distribution companies and municipalities, is subject to minimal credit
risk.  Transwestern establishes an allowance for doubtful accounts on
trade receivables based on the expected ultimate recovery of these
receivables.  Transwestern considers many factors including historical
customer collection experience, general and specific economic trends and known
specific issues related to individual customers, sectors and transactions that
might impact collectability.
  14
  ETP’s
propane operations grant credit to their customers for the purchase of propane
and propane-related products.  Included in accounts receivable are
trade accounts receivable arising from HOLP’s retail and wholesale propane and
Titan’s retail propane operations and receivables arising from liquids marketing
activities.  Accounts receivable for retail and wholesale propane
operations are recorded as amounts are billed to customers less an allowance for
doubtful accounts.  The allowance for doubtful accounts for the
propane segment is based on management’s assessment of the realizability of
customer accounts, based on the overall creditworthiness of our customers and
any specific disputes.
 
 We enter
into netting arrangements with counterparties of derivative contracts to
mitigate credit risk.  Transactions are confirmed with the
counterparty and the net amount is settled when due.  Amounts
outstanding under these netting arrangements are presented on a net basis in the
consolidated balance sheets.
 
 We
exchanged a portion of our outstanding accounts receivable from Calpine Energy
Services, L.P. for Calpine Corporation (“Calpine”) common stock valued at $10.8
million during the first quarter of 2008 pursuant to a settlement reached with
Calpine related to their bankruptcy reorganization.  The stock is
included in marketable securities on the consolidated balance sheet at a fair
value of $4.8 million as of December 31, 2008.  In 2009, we sold the
stock for $7.3 million and recorded a realized loss of $3.6 million, of which
$3.5 million was reclassified from AOCI to other income in the consolidated
statement of operations.
 
 Accounts
receivable consisted of the following:
 
 December 31,
                2009
              
              
              December 31,
                2008Natural
      gas operations
              
              $
              429,849
              
              
              $
              444,816Propane
              
              
              143,011
              
              
              
              155,191Less
      – allowance for doubtful accounts
              
              
              (6,338
              )
              
              
              (8,750
              )Total,
      net
              
              $
              566,522
              
              
              $
              591,257
 
 The
activity in the allowance for doubtful accounts consisted of the
following:
 
 Years Ended
    December 31,
              
              
              Four
      MonthsEndedDecember 31,
              
              
              YearEndedAugust 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Balance,
      beginning of the period
              
              $
              8,750
              
              
              $
              5,698
              
              
              $
              5,601
              
              
              $
              4,000Accounts
      receivable written off, net of recoveries
              
              
              (5,404
              )
              
              
              (4,963
              )
              
              
              (447
              )
              
              
              (2,628
              )Provision
      for loss on accounts receivable
              
              
              2,992
              
              
              
              8,015
              
              
              
              544
              
              
              
              4,229Balance,
      end of period
              
              $
              6,338
              
              
              $
              8,750
              
              
              $
              5,698
              
              
              $
              5,601
 
 Inventories
 
 Inventories
consist principally of natural gas held in storage valued at the lower of cost
or market utilizing the weighted-average cost method.  Propane
inventories are also valued at the lower of cost or market utilizing the
weighted-average cost of propane delivered to the customer service locations,
including storage fees and inbound freight costs.  The cost of
appliances, parts and fittings is determined by the first-in, first-out
method.
  15
  Inventories
consisted of the following:
 
 December 31,
                2009
              
              
              December 31,
                2008Natural
      gas and NGLs, excluding propane
              
              $
              157,103
              
              
              $
              184,727Propane
              
              
              66,686
              
              
              
              63,967Appliances,
      parts and fittings and other
              
              
              166,165
              
              
              
              23,654Total
      inventories
              
              $
              389,954
              
              
              $
              272,348
 
 We
utilize commodity derivatives to manage price volatility associated with our
natural gas inventory.  In April 2009, we began designating commodity
derivatives as fair value hedges for accounting purposes.  Subsequent
to the designation of those fair value hedging relationships, changes in fair
value of the designated hedged inventory have been recorded in inventory on our
consolidated balance sheet and have been recorded in cost of products sold in
our consolidated statements of operations.
 
 During
2009, we recorded lower of cost or market adjustments of $54.0 million, which
were offset by fair value adjustments related to our application of fair value
hedging of $66.1 million.
 
 During
2008, we recorded lower-of-cost-or-market adjustments of $69.5 million for
natural gas inventory and $4.4 million for propane inventory to reflect market
values, which were less than the weighted-average cost.  The natural
gas inventory adjustment in 2008 was partially offset in net income by the
recognition of unrealized gains on related cash flow hedges in the amount of
$21.7 million from AOCI.
 
 Exchanges
 
 The
midstream and intrastate transportation and storage segments’ exchanges consist
of natural gas and NGL delivery imbalances with others.  These
amounts, which are valued at market prices, turn over monthly and are recorded
as exchanges receivable or exchanges payable on our consolidated balance
sheets.  Management believes market value approximates
cost.
 
 The
interstate transportation segment’s natural gas imbalances occur as a result of
differences in volumes of gas received and delivered.  Transwestern
records natural gas imbalances for in-kind receivables and payables at the
dollar weighted composite average of all current month gas transactions and
dollar valued imbalances are recorded at contractual prices.
 
 Other
Current Assets
 
 Other
current assets consisted of the following:
 
 December 31,
                2009
              
              
              December 31,
                2008Deposits
      paid to vendors
              
              $
              79,694
              
              
              $
              78,237Prepaid
      and other
              
              
              70,018
              
              
              
              75,441Total
      other current assets
              
              $
              149,712
              
              
              $
              153,678
 
 Property,
Plant and Equipment
 
 Property,
plant and equipment are stated at cost less accumulated
depreciation.  Depreciation is computed using the straight-line method
over the estimated useful or Federal Energy Regulatory Commission (“FERC”)
mandated lives of the assets.  Expenditures for maintenance and
repairs that do not add capacity or extend the useful life are expensed as
incurred.  Expenditures to refurbish assets that either extend the
useful lives of the asset or prevent environmental contamination are capitalized
and depreciated over the remaining useful life of the
asset.  Additionally, we capitalize certain costs directly related to
the installation of company-owned propane tanks and construction of assets
including internal labor costs, interest and engineering costs.  Upon
disposition or retirement of pipeline components or natural gas plant
components, any gain or loss is recorded to accumulated
depreciation.  When entire pipeline systems, gas plants or other
property and equipment are retired or sold, any gain or loss is included in our
results of operations.
  16
  We review
property, plant and equipment for impairment whenever events or changes in
circumstances indicate that the carrying amount of such assets may not be
recoverable.  If such a review should indicate that the carrying
amount of long-lived assets is not recoverable, we reduce the carrying amount of
such assets to fair value.  No impairment of long-lived assets was
required during the periods presented.
 
 Capitalized
interest is included for pipeline construction projects, except for interstate
projects for which an allowance for funds used during construction (“AFUDC”) is
accrued.  Interest is capitalized based on the current borrowing rate
of ETP’s revolving credit facility when the related costs are
incurred.  AFUDC is calculated under guidelines prescribed by the FERC
and capitalized as part of the cost of utility plant for interstate
projects.  It represents the cost of servicing the capital invested in
construction work-in-process.  AFUDC is segregated into two component
parts – borrowed funds and equity funds.
 
 Components
and useful lives of property, plant and equipment were as follows:
 
 December 31,
                2009
              
              
              December 31,
                2008Land
      and improvements
              
              $
              87,388
              
              
              $
              74,895Buildings
      and improvements (10 to 40 years)
              
              
              160,912
              
              
              
              133,951Pipelines
      and equipment (10 to 83 years)
              
              
              7,388,889
              
              
              
              5,592,057Natural
      gas storage (40 years)
              
              
              100,746
              
              
              
              92,457Bulk
      storage, equipment and facilities (3 to 83 years)
              
              
              591,908
              
              
              
              533,621Tanks
      and other equipment (10 to 30 years)
              
              
              602,915
              
              
              
              578,118Vehicles
      (3 to 10 years)
              
              
              176,946
              
              
              
              156,486Right
      of way (20 to 83 years)
              
              
              516,709
              
              
              
              366,205Furniture
      and fixtures (3 to 10 years)
              
              
              32,810
              
              
              
              28,075Linepack
              
              
              53,404
              
              
              
              48,108Pad
      gas
              
              
              47,363
              
              
              
              53,583Other
      (5 to 10 years)
              
              
              117,896
              
              
              
              97,9759,877,886
              
              
              
              7,755,531Less
      – Accumulated depreciation
              
              
              (1,052,566
              )
              
              
              (762,014
              )8,825,320
              
              
              
              6,993,517Plus
      – Construction work-in-process
              
              
              239,155
              
              
              
              1,709,017Property,
      plant and equipment, net
              
              $
              9,064,475
              
              
              $
              8,702,534
 
 We
recognized the following amounts of depreciation expense, capitalized interest,
and AFUDC for the periods presented:
 
 Years Ended
    December 31,
              
              
              Four
      Months Ended December 31,
              
              
              Year
      Ended
                August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Depreciation
      expense
              
              $
              304,129
              
              
              $
              256,910
              
              
              $
              68,642
              
              
              $
              175,851Capitalized
      interest, excluding AFUDC
              
              $
              11,791
              
              
              $
              21,595
              
              
              $
              12,657
              
              
              $
              22,979AFUDC
      (both debt and equity components)
              
              $
              10,237
              
              
              $
              50,074
              
              
              $
              5,095
              
              
              $
              3,600
 
 Advances
to and Investment in Affiliates
 
 We own
interests in a number of related businesses that are accounted for using the
equity method.  In general, we use the equity method of accounting for
an investment in which we have a 20% to 50% ownership and exercise significant
influence over, but do not control the investee’s operating and financial
policies.
 
 We
account for our investments in Midcontinent Express Pipeline LLC and
Fayetteville Express Pipeline LLC using the equity method.  See Note 4
for a discussion of these joint ventures.
  17
  Goodwill
 
 Goodwill
is tested for impairment annually or more frequently if circumstances indicate
that goodwill might be impaired.  Our annual impairment test is
performed as of December 31 for subsidiaries in our interstate segment and as of
August 31 for all others.  At December 31, 2008, we recorded an
impairment of the entire goodwill balance of $11.4 million related to the Canyon
Gathering System.  No other goodwill impairments were recorded for the
periods presented in these consolidated financial statements.  Changes
in the carrying amount of goodwill were as follows:
 
 Intrastate
      Transportation and
      Storage
              
              
              Interstate
      Transportation
              
              
              Midstream
              
              
              Retail
      Propane
              
              
              All
      Other
              
              
              TotalBalance
      as of December 31, 2007
              
              $
              10,327
              
              
              $
              98,613
              
              
              $
              24,368
              
              
              $
              594,801
              
              
              $
              29,589
              
              
              $
              757,698Purchase
      accounting adjustments
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              2,457
              
              
              
              -
              
              
              
              2,457Goodwill
      acquired
              
              
              -
              
              
              
              -
              
              
              
              9,141
              
              
              
              15,346
              
              
              
              -
              
              
              
              24,487Goodwill
      impairment
              
              
              -
              
              
              
              -
              
              
              
              (11,359
              )
              
              
              -
              
              
              
              -
              
              
              
              (11,359
              )Balance
      as of December 31, 2008
              
              
              10,327
              
              
              
              98,613
              
              
              
              22,150
              
              
              
              612,604
              
              
              
              29,589
              
              
              
              773,283Purchase
      accounting adjustments
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (8,662
              )
              
              
              -
              
              
              
              (8,662
              )Goodwill
      acquired
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              33
              
              
              
              10,440
              
              
              
              10,473Balance
      as of December 31, 2009
              
              $
              10,327
              
              
              $
              98,613
              
              
              $
              22,150
              
              
              $
              603,975
              
              
              $
              40,029
              
              
              $
              775,094
 
 Goodwill
is recorded at the acquisition date based on a preliminary purchase price
allocation and generally may be adjusted when the purchase price allocation is
finalized.
 
 Intangibles
and Other Assets
 
 Intangibles
and other assets are stated at cost, net of amortization computed on the
straight-line method.  We eliminate from our balance sheet the gross
carrying amount and the related accumulated amortization for any fully amortized
intangibles in the year they are fully amortized.  Components and
useful lives of intangibles and other assets were as follows:
 
 December 31, 2009
              
              
              December 31, 2008Gross
      Carrying Amount
              
              
              Accumulated
      Amortization
              
              
              Gross
      Carrying Amount
              
              
              Accumulated
      AmortizationAmortizable
      intangible assets:Noncompete
      agreements (3 to 15 years)
              
              $
              24,139
              
              
              $
              (12,415
              )
              
              $
              40,301
              
              
              $
              (24,374
              )Customer
      lists (3 to 30 years)
              
              
              153,843
              
              
              
              (53,123
              )
              
              
              144,337
              
              
              
              (39,730
              )Contract
      rights (6 to 15 years)
              
              
              23,015
              
              
              
              (5,638
              )
              
              
              23,015
              
              
              
              (3,744
              )Patents
      (9 years)
              
              
              750
              
              
              
              (35
              )
              
              
              -
              
              
              
              -Other
      (10 years)
              
              
              478
              
              
              
              (397
              )
              
              
              2,677
              
              
              
              (2,244
              )Total
      amortizable intangible assets
              
              
              202,225
              
              
              
              (71,608
              )
              
              
              210,330
              
              
              
              (70,092
              )Non-amortizable
      intangible assets:Trademarks
              
              
              75,825
              
              
              
              -
              
              
              
              75,667
              
              
              
              -Total
      intangible assets
              
              
              278,050
              
              
              
              (71,608
              )
              
              
              285,997
              
              
              
              (70,092
              )Other
      assets:Financing
      costs (3 to 30 years)
              
              
              84,099
              
              
              
              (34,702
              )
              
              
              74,611
              
              
              
              (23,508
              )Regulatory
      assets
              
              
              101,879
              
              
              
              (9,501
              )
              
              
              98,560
              
              
              
              (5,941
              )Other
      assets
              
              
              41,466
              
              
              
              -
              
              
              
              43,353
              
              
              
              -Total
      intangibles and other assets
              
              $
              505,494
              
              
              $
              (115,811
              )
              
              $
              502,521
              
              
              $
              (99,541
              )
  18
  Aggregate
amortization expense of intangible and other assets are as follows:
 
 Years Ended
    December 31,
              
              
              Four
      Months Ended December 31,
              
              
              Year
      Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Reported
      in depreciation and amortization
              
              $
              20,895
              
              
              $
              17,462
              
              
              $
              6,764
              
              
              $
              15,532Reported
      in interest expense
              
              $
              11,195
              
              
              $
              9,015
              
              
              $
              2,716
              
              
              $
              7,132
 
 Estimated
aggregate amortization expense for the next five years is as
follows:
 
 Years Ending
    December 31:2010
              
              $
              29,9622011
              
              
              27,5532012
              
              
              22,1172013
              
              
              16,3102014
              
              
              15,343
 
 We review
amortizable intangible assets for impairment whenever events or changes in
circumstances indicate that the carrying amount of such assets may not be
recoverable.  If such a review should indicate that the carrying
amount of amortizable intangible assets is not recoverable, we reduce the
carrying amount of such assets to fair value.  We review
non-amortizable intangible assets for impairment annually, or more frequently if
circumstances dictate.  Our annual impairment test is performed as of
December 31 for our interstate segment and as of August 31 for all
others.  No impairment of intangible assets was required during the
periods presented in these consolidated financial statements.
 
 Asset
Retirement Obligation
 
 We record
the fair value of an asset retirement obligation as a liability in the period a
legal obligation for the retirement of tangible long-lived assets is incurred,
typically at the time the assets are placed into service.  A
corresponding asset is also recorded and depreciated over the life of the
asset.  After the initial measurement, we also recognize changes in
the amount of the liability resulting from the passage of time and revisions to
either the timing or amount of estimated cash flows.
 
 We have
determined that we are obligated by contractual requirements to remove
facilities or perform other remediation upon retirement of certain
assets.  Determination of the amounts to be recognized is based upon
numerous estimates and assumptions, including expected settlement dates, future
retirement costs, future inflation rates and the credit-adjusted risk-free
interest rates.  However, management was not able to reasonably
measure the fair value of the asset retirement obligations as of December 31,
2009 or 2008 because the settlement dates were indeterminable.  An
asset retirement obligation will be recorded in the periods management can
reasonably determine the settlement dates.
  19
  Accrued
and Other Current Liabilities
 
 Accrued
and other current liabilities consisted of the following:
 
 December 31,
                2009
              
              
              December 31,
                2008Customer
      advances and deposits
              
              $
              88,430
              
              
              $
              106,679Accrued
      capital expenditures
              
              
              46,134
              
              
              
              153,230Accrued
      wages and benefits
              
              
              25,577
              
              
              
              65,754Taxes
      other than income taxes
              
              
              23,294
              
              
              
              20,772Income
      taxes payable
              
              
              3,154
              
              
              
              14,298Deferred
      income taxes
              
              
              -
              
              
              
              589Other
              
              
              42,484
              
              
              
              73,384Total
      accrued and other current liabilities
              
              $
              229,073
              
              
              $
              434,706
 
 Customer
Advances and Deposits
 
 Deposits
or advances are received from our customers as prepayments for natural gas
deliveries in the following month and from our propane customers as security or
prepayments for future propane deliveries.  Prepayments and security
deposits may also be required when customers exceed their credit limits or do
not qualify for open credit.
 
 Fair
Value of Financial Instruments
 
 The
carrying amounts of accounts receivable and accounts payable approximate their
fair value.  Price risk management assets and liabilities are recorded
at fair value.  Based on the estimated borrowing rates currently
available to us and our subsidiaries for long-term loans with similar terms and
average maturities, the aggregate fair value and carrying amount of long-term
debt at December 31, 2009 was $8.25 billion and $7.79 billion,
respectively.  At December 31, 2008, the aggregate fair value and
carrying amount of long-term debt was $6.41 billion and $7.24 billion,
respectively.
 
 We have
marketable securities, commodity derivatives and interest rate derivatives that
are accounted for as assets and liabilities at fair value in our consolidated
balance sheets.  We determine the fair value of our assets and
liabilities subject to fair value measurement by using the highest possible
“level” of inputs.  Level 1 inputs are observable quotes in an active
market for identical assets and liabilities.  We consider the
valuation of marketable securities and commodity derivatives transacted through
a clearing broker with a published price from the appropriate exchange as a
Level 1 valuation.  Level 2 inputs are inputs observable for similar
assets and liabilities.  We consider over-the-counter (“OTC”)
commodity derivatives entered into directly with third parties as a Level 2
valuation since the values of these derivatives are quoted on an exchange for
similar transactions.  We consider the valuation of our interest rate
derivatives as Level 2 since we use a LIBOR curve based on quotes from an active
exchange of Eurodollar futures for the same period as the future interest swap
settlements and discount the future cash flows accordingly, including the
effects of our credit risk.  We currently do not have any fair value
measurements that require the use of significant unobservable inputs and
therefore do not have any assets or liabilities considered as Level 3
valuations.
  20
  The
following table summarizes the fair value of our financial assets and
liabilities as of December 31, 2009 and 2008 based on inputs used to derive
their fair values:
 
 Fair
      Value Measurements at at December 31,
      2009 Using
              
              
              Fair
      Value Measurements at December 31, 2008
      UsingFair
      Value
              
              
              Quoted
      Prices in Active Markets for Identical Assets and
    Liabilities
              
              
              Significant
      Other Observable Inputs
              
              
              Fair
      Value
              
              
              Quoted
      Prices in Active Markets for Identical Assets and
      Liabilities
              
              
              Significant
      Other Observable InputsDescription
              
              Total
              
              
              (Level 1)
              
              
              (Level 2)
              
              
              Total
              
              
              (Level 1)
              
              
              (Level 2)Assets:Marketable
      securities
              
              $
              6,055
              
              
              $
              6,055
              
              
              $
              -
              
              
              $
              5,915
              
              
              $
              5,915
              
              
              $
              -Inventories
              
              
              156,156
              
              
              
              156,156
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Commodity
      derivatives
              
              
              32,479
              
              
              
              20,090
              
              
              
              12,389
              
              
              
              111,513
              
              
              
              106,090
              
              
              
              5,423Liabilities:Commodity
      derivatives
              
              
              (8,016
              )
              
              
              (7,574
              )
              
              
              (442
              )
              
              
              (43,336
              )
              
              
              -
              
              
              
              (43,336
              )Interest
      rate swap derivatives
              
              
              (138,036
              )
              
              
              -
              
              
              
              (138,036
              )
              
              
              (220,806
              )
              
              
              -
              
              
              
              (220,806
              )$
              48,638
              
              
              $
              174,727
              
              
              $
              (126,089
              )
              
              $
              (146,714
              )
              
              $
              112,005
              
              
              $
              (258,719
              )
 
 Contributions
in Aid of Construction Costs
 
 On
certain of our capital projects, third parties are obligated to reimburse us for
all or a portion of project expenditures.  The majority of such
arrangements are associated with pipeline construction and production well
tie-ins.  Contributions in aid of construction costs (“CIAC”) are
netted against our project costs as they are received, and any CIAC which
exceeds our total project costs, is recognized as other income in the period in
which it is realized.  In March 2008, we received a reimbursement
related to an extension on our Southeast Bossier pipeline resulting in an excess
over total project costs of $7.1 million, which is recorded in other income on
our consolidated statement of operations for the year ended December 31,
2008.
 
 Contributions
in aid of construction costs were as follows:
 
 Years Ended
    December 31,
              
              
              Four
      Months Ended December 31,
              
              
              Year
      Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Received
      and netted against project costs
              
              $
              6,453
              
              
              $
              50,050
              
              
              $
              3,493
              
              
              $
              10,463Recorded
      in other income
              
              
              (305
              )
              
              
              8,352
              
              
              
              216
              
              
              
              403Total
              
              $
              6,148
              
              
              $
              58,402
              
              
              $
              3,709
              
              
              $
              10,866
 
 Shipping
and Handling Costs
 
 Shipping
and handling costs related to fuel sold are included in cost of products
sold.  Shipping and handling costs related to fuel consumed for
compression and treating are included in operating expenses and totaled $55.9
million and $112.0 million for the years ended December 31, 2009 and 2008,
respectively, $30.7 million for the four months ended December 31, 2007, and
$58.6 million for the year ended August 31, 2007.  We do not
separately charge propane shipping and handling costs to customers.
 
 Costs and
Expenses
 
 Costs of
products sold include actual cost of fuel sold, adjusted for the effects of our
hedging and other commodity derivative activities, storage fees and inbound
freight on propane, and the cost of appliances, parts and
fittings.  Operating expenses include all costs incurred to provide
products to customers, including compensation for operations personnel,
insurance costs, vehicle maintenance, advertising costs, shipping and handling
costs related to propane, purchasing costs and plant
operations.  Selling, general and administrative expenses include all
partnership related expenses and compensation for executive, partnership, and
administrative personnel.
  21
  We record
the collection of taxes to be remitted to governmental authorities on a net
basis.
 
 Issuances
of Subsidiary Units
 
 We record
changes in our ownership interest of our subsidiaries as equity transactions,
with no gain or loss recognized in consolidated net income or comprehensive
income.  For example, upon ETP’s issuance of ETP Common Units in a
public offering, we record any difference between the amount of consideration
received or paid and the amount by which the noncontrolling interest is adjusted
as a change in partners’ capital.
 
 Income
Taxes
 
 ETE is a
limited partnership.  As a result, our earnings or losses, to the
extent not included in a taxable subsidiary, for federal and state income tax
purposes are included in the tax returns of the individual
partners.  Net earnings for financial statement purposes may differ
significantly from taxable income reportable to Unitholders as a result of
differences between the tax basis and financial reporting basis of assets and
liabilities, in addition to the allocation requirements related to taxable
income under the Second Amended and Restated Agreement of Limited Partnership
(the “Partnership Agreement”).
 
 Our
partnership will be considered to have terminated for federal income tax
purposes if transfers of units within a 12-month period constitute the sale or
exchange of 50% or more of our capital and profits interests.  In
order to determine whether a sale or exchange of 50% or more of capital and
profits interests has occurred, we review information available to us regarding
transactions involving transfers of our units, including reported transfers of
units by our affiliates and sales of units pursuant to trading activity in the
public markets; however, the information we are able to obtain is generally not
sufficient to make a definitive determination, on a current basis, of whether
there have been sales and exchanges of 50% or more of our capital and profits
interests within the prior 12-month period, and we may not have all of the
information necessary to make this determination until several months following
the time of the transfers that would cause the 50% threshold to be
exceeded.
 
 We
exceeded the 50% threshold on May 7, 2007, and, as a result, our partnership
terminated for federal tax income purposes on that date.  Our
termination also caused ETP to terminate for federal income tax purposes on that
date.  These terminations did not affect our classification or the
classification of ETP as a partnership for federal income tax purposes or
otherwise affect the nature or extent of our “qualifying income” or the
“qualifying income” of ETP for federal income tax purposes.  These
terminations required both us and ETP to close our taxable years and to make new
elections as to various tax matters.  In addition, ETP was required to
reset the depreciation schedule for its depreciable assets for federal income
tax purposes.  The resetting of ETP’s depreciation schedule resulted
in a deferral of the depreciation deductions allowable in computing the taxable
income allocated to the Unitholders of ETP and, consequently, to our
Unitholders.  However, elections ETP and ETE made with respect to the
amortization of certain intangible assets had the effect of reducing the amount
of taxable income that would otherwise be allocated to ETE
Unitholders.
 
 As a
result of the tax termination discussed above, we elected new depreciation and
amortization policies for income tax purposes, which include the amortization of
goodwill.  As a result of the income tax regulations related to
remedial income allocations, ETP’s subsidiary, Heritage Holdings, Inc. (“HHI”),
which owns ETP’s Class E units, receives a special allocation of taxable income,
for income tax purposes only, essentially equal to the amount of goodwill
amortization deductions allocated to purchasers of ETP Common
Units.  The amount of such “goodwill” accumulated as of the date of
ETP’s acquisition of HHI (approximately $158.0 million) is now being amortized
over 15 years beginning on May 7, 2007, the date of our new tax
elections.  ETP accounts for HHI using the treasury stock method due
to its ownership of ETP’s Class E units.  ETP accounts for the tax
effects of the goodwill amortization and remedial income allocation as an
adjustment of ETP’s HHI purchase price allocation, which effectively results in
a charge to ETP’s common equity and a deferred tax benefit offsetting the
current tax expense resulting from the remedial income allocation for tax
purposes.  For the years ended December 31, 2009 and 2008, the four
months ended December, 31, 2007, and the year ended August 31, 2007, this
resulted in a current tax expense and deferred tax benefit (with a corresponding
charge to common equity as an adjustment of the purchase price allocation) of
approximately $3.8 million, $3.4 million, $1.2 million and $1.2 million,
respectively.  As of December 31, 2009, the amount of tax goodwill to
be amortized over the next 13 years for which HHI will receive a remedial income
allocation is approximately $132.8 million.
  22
  As a
limited partnership, we are generally not subject to income tax.  We
are, however, subject to a statutory requirement that our non-qualifying income
(including income such as derivative gains from trading activities, service
income, tank rentals and others) cannot exceed 10% of our total gross income,
determined on a calendar year basis under the applicable income tax
provisions.  If the amount of our non-qualifying income exceeds this
statutory limit, we would be taxed as a corporation.  Accordingly,
certain activities that generate non-qualifying income are conducted through
taxable corporate subsidiaries (“C corporations”).  These C
corporations are subject to federal and state income tax and pay the income
taxes related to the results of their operations.  For the years ended
December 31, 2009 and 2008, the four months ended December 31, 2007 and the year
ended August 31, 2007, our non-qualifying income did not exceed the statutory
limit.
 
 Those
subsidiaries which are taxable corporations follow the asset and liability
method of accounting for income taxes, under which deferred income taxes are
recorded based upon differences between the financial reporting and tax basis of
assets and liabilities and are measured using the enacted tax rates and laws
that will be in effect when the underlying assets are received and liabilities
settled.
 
 Accounting
for Derivative Instruments and Hedging Activities
 
 We are
exposed to market risks related to the volatility of natural gas, NGL and
propane prices.  To manage the impact of volatility from these prices,
we utilize various exchange-traded and OTC commodity financial instrument
contracts.  These contracts consist primarily of futures and swaps and
are recorded at fair value in the consolidated balance sheets.  In
general, we use derivatives to eliminate market exposure and price risk within
our segments as follows:
 
 ·
              Derivatives
      are utilized in our midstream segment in order to mitigate price
      volatility in our marketing activities and manage fixed price exposure
      incurred from contractual
obligations.
 
 ·
              We
      use derivative financial instruments in connection with our natural gas
      inventory at the Bammel storage facility by purchasing physical natural
      gas and then selling financial contracts at a price sufficient to cover
      its carrying costs and provide a gross profit margin.  We also
      use derivatives in our intrastate transportation and storage segment to
      hedge the sales price of retention gas and hedge location price
      differentials related to the transportation of natural
  gas.
 
 ·
              Our
      propane segment permits customers to guarantee the propane delivery price
      for the next heating season.  As we execute fixed sales price
      contracts with our customers, we may enter into propane futures contracts
      to fix the purchase price related to these sales contracts, thereby
      locking in a gross profit margin.  Additionally, we may use
      propane futures contracts to secure the purchase price of our propane
      inventory for a percentage of our anticipated propane
    sales.
 
 For
qualifying hedges, we formally document, designate and assess the effectiveness
of transactions that receive hedge accounting treatment and the gains and losses
offset related results on the hedged item in the statement of
operations.  The market prices used to value our financial derivatives
and related transactions have been determined using independent third party
prices, readily available market information, broker quotes and appropriate
valuation techniques.
 
 At
inception of a hedge, we formally document the relationship between the hedging
instrument and the hedged item, the risk management objectives, and the methods
used for assessing and testing effectiveness and how any ineffectiveness will be
measured and recorded.  We also assess, both at the inception of the
hedge and on a quarterly basis, whether the derivatives that are used in our
hedging transactions are highly effective in offsetting changes in cash
flows.  If we determine that a derivative is no longer highly
effective as a hedge, we discontinue hedge accounting prospectively by including
changes in the fair value of the derivative in net income for the
period.
 
 If we
designate a hedging relationship as a fair value hedge, we record the changes in
fair value of the hedged asset or liability in cost of products sold in our
consolidated statement of operations.  This amount is offset by the
changes in fair value of the related hedging instrument.  Any
ineffective portion or amount excluded from the assessment of hedge
ineffectiveness is also included in the cost of products sold in the
consolidated statement of operations.
 
 We inject
and hold natural gas in our Bammel storage facility to take advantage of
contango markets, when the price of natural gas is higher in the future than the
current spot price.  We use financial derivatives to hedge the natural
gas held in connection with these arbitrage opportunities.  At the
inception of the hedge, we lock in a margin by purchasing gas in the spot market
or off peak season and entering a financial contract to lock in the sale
price.  If we designate the related financial contract as a fair value
hedge for accounting purposes, we value the hedged natural gas inventory at
current spot market prices along with the financial derivative we use to hedge
it.  Changes in the spread between the forward natural gas prices
designated as fair value hedges and the physical inventory spot price result in
unrealized gains or losses until the underlying physical gas is withdrawn and
the related designated derivatives are settled.  Once the gas is
withdrawn and the designated derivatives are settled, the previously unrealized
gains or losses associated with these positions are
realized.  Unrealized margins represent the unrealized gains or losses
from our derivative instruments using marked to market accounting with changes
in the fair value of our derivatives being recorded directly in
earnings.  These margins fluctuate based upon changes in the spreads
between the physical spot price and forward natural gas prices.  If
the spread narrows between the physical and financial prices, we will record
unrealized gains or lower unrealized losses.  If the spread widens, we
will record unrealized losses or lower unrealized gains.  Typically,
as we enter the winter months, the spread converges so that we recognize in
earnings the original locked in spread, either through mark-to-market or the
physical withdrawal of natural gas.
  23
  We
attempt to maintain balanced positions in our marketing activities to protect
ourselves from the volatility in the energy commodities markets; however, net
unbalanced positions can exist.  Long-term physical contracts are tied
to index prices.  System gas, which is also tied to index prices, is
expected to provide most of the gas required by our long-term physical
contracts.  When third-party gas is required to supply long-term
contracts, a hedge is put in place to protect the margin on the
contract.  Financial contracts, which are not tied to physical
delivery, are expected to be offset with financial contracts to balance our
positions.  To the extent open commodity positions exist, fluctuating
commodity prices can impact our financial position and results of operations,
either favorably or unfavorably.
 
 Cash
flows from derivatives accounted for as cash flow hedges are reported as cash
flows from operating activities, in the same category as the cash flows from the
items being hedged.
 
 If we
designate a derivative financial instrument as a cash flow hedge and it
qualifies for hedge accounting, a change in the fair value is deferred in AOCI
until the underlying hedged transaction occurs.  Any ineffective
portion of a cash flow hedge’s change in fair value is recognized each period in
earnings.  Gains and losses deferred in AOCI related to cash flow
hedges remain in AOCI until the underlying physical transaction occurs, unless
it is probable that the forecasted transaction will not occur by the end of the
originally specified time period or within an additional two-month period of
time thereafter.  For financial derivative instruments that do not
qualify for hedge accounting, the change in fair value is recorded in cost of
products sold in the consolidated statements of operations.
 
 We are
exposed to market risk for changes in interest rates related to our revolving
credit facilities.  We previously have managed a portion of our
interest rate exposures by utilizing interest rate swaps and similar
arrangements, which allow us to effectively convert a portion of variable rate
debt into fixed rate debt.  Certain of our interest rate derivatives
are accounted for as cash flow hedges.  We report the realized gain or
loss and ineffectiveness portions of those hedges in interest
expense.  Gains and losses on interest rate derivatives that are not
accounted for as cash flow hedges are classified in other income.
 
 Allocation
of Income (Loss)
 
 For
purposes of maintaining partner capital accounts, our Partnership Agreement
specifies that items of income and loss shall generally be allocated among the
partners in accordance with their percentage interests (see Note
7).
 
 Unit-Based
Compensation
 
 We
recognize compensation expense for equity awards issued to employees over the
vesting period based on the grant-date fair value.  The grant-date
fair value is determined based on the market price of our Common Units on the
grant date, adjusted to reflect the present value of any expected distributions
that will not accrue to the employee during the vesting period.  The
present value of expected service period distributions is computed based on the
risk-free interest rate, the expected life of the unit grants and the expected
unit distributions based on the most recently declared distributions as of the
grant date.
  24
  New
Accounting Standards
 
 Accounting Standards
Codification.  On July 1, 2009, the Financial Accounting
Standards Board (“FASB”) instituted a new referencing system, which codifies,
but does not amend, previously existing nongovernmental U.S. generally accepted
accounting principles (“GAAP”).  The FASB Accounting Standards
Codification (“ASC”) is now the single authoritative source for
GAAP.  Although the implementation of ASC has no impact on our
financial statements, certain references to authoritative GAAP literature within
our footnotes have been changed to cite the appropriate content within the
ASC.
 
 Noncontrolling
Interests.  On January 1, 2009, we adopted SFAS 160, now
incorporated into ASC 810-10, which established new accounting and reporting
standards for the noncontrolling interest in a subsidiary and for the
deconsolidation of a subsidiary.  Specifically, the new standard
requires the recognition of a noncontrolling interest (minority interest) as
equity in the consolidated financial statements and separate from the parent's
equity.  The amount of net income attributable to the noncontrolling
interest is included in consolidated net income on the face of the income
statement.  The new standard clarifies that changes in a parent's
ownership interest in a subsidiary that do not result in deconsolidation are
equity transactions if the parent retains its controlling financial
interest.  In addition, the new standard requires that a parent
recognizes a gain or loss in net income when a subsidiary is
deconsolidated.  Such gain or loss is measured using the fair value of
the noncontrolling equity investment on the deconsolidation
date.  This standard also includes expanded disclosure requirements
regarding the interests of the parent and its noncontrolling
interest.  The adoption of this standard did not have a significant
impact on our financial position or results of operations.  However,
it did result in certain changes to our financial statement presentation,
including the change in classification of noncontrolling interest (minority
interest) from liabilities to equity on the condensed consolidated balance
sheet.
 
 Upon
adoption, we reclassified $2.42 billion from minority interest liability to
noncontrolling interest as a separate component of equity in our consolidated
balance sheet as of December 31, 2008.  In addition, we reclassified
$304.7 million, $90.1 million and $232.6 million of minority interest expense to
net income attributable to noncontrolling interest in our consolidated
statements of operations for the year ended December 31, 2008, the four month
transition period ended December 31, 2007 and the year ended August 31,
2007.  Net income per limited partner unit has not been affected as a
result of the adoption of this standard.
 
 Earnings per
Unit.  On January 1, 2009, we adopted a new methodology for
calculating earnings per unit to reflect recently ratified changes to accounting
standards.  This new standard was originally issued as Emerging Issues
Task Force Issue No. 07-4, Application of the Two-Class Method
under FASB Statement No. 128 to Master Limited Partnerships, and is now
incorporated into ASC 260-10.  Our adoption of this standard did not
have an impact on the calculation of ETE’s earnings per unit.
 
 On
January 1, 2009, we also adopted FASB Staff Position No. EITF 03-6-1, Determining Whether Instruments
Granted in Share-Based Payment Transactions Are Participating Securities,
which is now incorporated into ASC 260-10.  This standard clarifies
that unvested share-based payment awards constitute participating securities, if
such awards include nonforfeitable rights to dividends or dividend
equivalents.  Consequently, awards that are deemed to be participating
securities must be allocated earnings in the computation of earnings per share
under the two-class method.  Based on unvested unit awards outstanding
at the time of adoption, application of this standard did not have a material
impact on our computation of earnings per unit.
 
 Business
Combinations.On January 1, 2009, we adopted Statement of
Financial Accounting Standards No. 141 (Revised 2007), Business Combinations,which
is now incorporated into ASC 805.  The new standard significantly
changes the accounting for business combinations and includes a substantial
number of new disclosure requirements.  The new standard requires an
acquiring entity to recognize all the assets acquired and liabilities assumed in
a transaction at the acquisition-date fair value with limited exceptions and
changes the accounting treatment for certain specific items,
including:
 
 ·
              Acquisition
      costs are generally expensed as
incurred;
 
 ·
              Noncontrolling
      interests (previously referred to as "minority interests") are valued at
      fair value at the acquisition date;
 
 ·
              In-process
      research and development is recorded at fair value as an indefinite-lived
      intangible asset at the acquisition
date;
  25
  ·
              Restructuring
      costs associated with a business combination are generally expensed
      subsequent to the acquisition date;
and
 
 ·
              Changes
      in deferred tax asset valuation allowances and income tax uncertainties
      after the acquisition date are recorded in income
  taxes.
 
 Our
adoption of this standard did not have an immediate impact on our financial
position or results of operations; however, it has impacted the accounting for
our business combinations subsequent to adoption.
 
 Derivative Instruments and Hedging
Activities.On January 1, 2009, we adopted Statement of
Financial Accounting Standards No. 161, Disclosures about Derivative
Instruments and Hedging Activities - An Amendment of FASB Statement No.
133, which is now incorporated into ASC 815.This standard
changed the disclosure requirements for derivative instruments and hedging
activities, including requirements for qualitative disclosures about objectives
and strategies for using derivatives, quantitative disclosures about fair value
amounts and gains and losses on derivative instruments, and disclosures about
credit-risk-related contingent features in derivative agreements.  The
standard only affected disclosure requirements; therefore, our adoption did not
impact our financial position or results of operations.
 
 Equity Method Investment
Accounting.On January 1, 2009, we adopted Emerging Issues
Task Force Issue No. 08-6, Equity Method Investment Accounting
Considerations,which is now incorporated into ASC
323-10.  This standard establishes the requirements for initial
measurement of an equity method investment, including the accounting for
contingent consideration related to the acquisition of an equity method
investment, and also clarifies the accounting for (1) an other-than-temporary
impairment of an equity method investment and (2) changes in level of ownership
or degree of influence with respect to an equity method
investment.  Our adoption did not have a material impact on our
financial position or results of operations.
 
 Subsequent
Events.During 2009, we adopted Statement of Financial
Accounting Standards No. 165, Disclosures about Subsequent
Events, which is now incorporated into ASC 855.  Under this
standard, we are required to evaluate subsequent events through the date that
our financial statements are issued and also required to disclose the date
through which subsequent events are evaluated.  The adoption of this
standard does not change our current practices with respect to evaluating,
recording and disclosing subsequent events; therefore, our adoption of this
statement during the second quarter had no impact on our financial position or
results of operations.
 
 3.
              ACQUISITIONS:
 
 Proposed
Transaction
 
 We have
agreed to purchase a natural gas gathering company which provides dehydration,
treating, redelivery and compression services on a 120-mile pipeline system in
the Haynesville Shale.  The purchase price is $150 million in cash,
excluding certain adjustments as defined in the purchase agreement, and the
acquisition is expected to close in March 2010.
 
 2009
 
 In
November 2009, we acquired all of the outstanding equity interests of a natural
gas compression equipment business with operations in Arkansas, California,
Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas, in exchange
for the issuance of 1,450,076 ETP Common Units having an aggregate market value
of approximately $63.3 million on the closing date.  In connection
with this transaction, we received cash of $41.1 million, assumed total
liabilities of $30.5 million, which includes $8.4 million in notes payable and
recorded goodwill of $8.7 million.  In addition, we acquired ETG in
August 2009.  See Note 14.
 
 2008
 
 During
the year ended December 31, 2008, HOLP and Titan collectively acquired
substantially all of the assets of 20 propane businesses.  The
aggregate purchase price for these acquisitions totaled $96.4 million, which
included $76.2 million of cash paid, net of cash acquired, liabilities assumed
of $ 8.2 million, 53,893 Common Units issued valued at $2.2 million and debt
forgiveness of $9.8 million.  The cash paid for acquisitions was
financed primarily with ETP’s and HOLP’s Senior Revolving Credit
Facilities.  We recorded $15.3 million of goodwill in connection with
these acquisitions.
  26
  Transition
Period 2007
 
 Canyon
Acquisition
 
 In
October 2007, ETP acquired the Canyon Gathering System midstream business of
Canyon Gas Resources, LLC from Cantera Resources Holdings, LLC (the “Canyon
acquisition”) for $305.2 million in cash, subject to working capital adjustments
as defined in the purchase and sale agreement.  The purchase price was
initially allocated based on the estimated fair values of the assets acquired
and liabilities assumed at the date of the acquisition.  We completed
the purchase price allocation during the third quarter of 2008.  The
adjustments to the purchase price allocation were not material.
 
 The final
allocations of the purchase price are noted below:
 
 Accounts
      receivable
              
              $
              3,613Inventory
              
              
              183Prepaid
      and other current assets
              
              
              1,606Property,
      plant, and equipment
              
              
              284,910Intangibles
      and other assets
              
              
              6,351Goodwill
              
              
              11,359Total
      assets acquired
              
              
              308,022Accounts
      payable
              
              
              (1,840
              )Customer
      advances and deposits
              
              
              (1,030
              )Total
      liabilities assumed
              
              
              (2,870
              )Net
      assets acquired
              
              $
              305,152
 
 2007
 
 On
November 1, 2006, the Parent Company acquired from Energy Transfer Investments,
L.P. (“ETI”, a partnership also controlled by LE GP) the remaining 50% of the
Class B Limited Partner interests in ETP GP owned by ETI.  The Parent
Company recorded this acquisition at ETI’s historical cost of $4.5 million as
required under GAAP due to the fact that the Parent Company and ETI are
companies under common control.  As a result, the Parent Company now
owns 100% of the Incentive Distribution Rights of ETP.  The
acquisition was effected through the issuance of 83,148,900 newly created Parent
Company Class C Units and the assumption by the Parent Company of approximately
$70.5 million of ETI’s indebtedness.  The assumption of this debt
represents a non-cash financing activity.  The Class C Units were
recorded at the net value of the debt assumption (accounted for as a
distribution to ETI) and the value of the ETP GP Class B Units acquired, a net
amount of $66.0 million.  The Class C Units had essentially the same
voting rights and rights to distributions as the Common Units and Class B
Units.  The Class C Units converted into Common Units upon approval by
the ETE Common Unitholders on February 22, 2007.
 
 Also on
November 1, 2006, the Parent Company acquired additional limited partner
interests in ETP (Class G Units, which subsequently converted to Common Units on
May 1, 2007, see Note 7) which increased the Parent Company’s aggregate
ownership in ETP’s limited partner interests to approximately 46%.
 
 On
November 1, 2006, pursuant to agreements entered into with GE Energy Financial
Services (“GE”) and Southern Union Company (“Southern Union”), ETP acquired the
member interests in CCE Holdings, LLC (“CCEH”) from GE and certain other
investors for $1.00 billion.  ETP financed a portion of the CCEH
purchase price with the proceeds from its issuance of 26,086,957 Class G Units
to the Parent Company simultaneous with the closing on November 1,
2006.  The member interests acquired represented a 50% ownership in
CCEH.  On December 1, 2006, in a second and related transaction, CCEH
redeemed ETP’s 50% ownership interest in CCEH in exchange for 100% ownership of
Transwestern, which owns the Transwestern pipeline.  Following the
final step, Transwestern became a new operating subsidiary and formed the
interstate transportation segment of ETP.
  27
  The total
acquisition cost for Transwestern, net of cash acquired, was as
follows:
 
 Basis
      of investment in CCEH at November 30, 2006
              
              $
              956,348Distributions
      received on December 1, 2006
              
              
              (6,217
              )Fair
      value of short-term debt assumed
              
              
              13,000Fair
      value of long-term debt assumed
              
              
              519,377Other
      assumed long-term indebtedness
              
              
              10,096Current
      liabilities assumed
              
              
              35,781Cash
      acquired
              
              
              (3,386
              )Acquisition
      costs incurred
              
              
              11,696Total
              
              $
              1,536,695
 
 In
September 2006, ETP acquired two small natural gas gathering systems in east and
north Texas for an aggregate purchase price of approximately $30.6 million in
cash.  The purchase and sale agreement for the gathering system in
north Texas also had a contingent payment not to exceed $25.0 million to be
determined eighteen months from the closing date.  These systems
provide us with additional capacity in the Barnett Shale and in the Travis Peak
area of east Texas and are included in our midstream operating
segment.  The cash paid for this acquisition was financed primarily
from advances under the previously existing credit facility.  In March
2008, a contingent payment of $8.7 million was recorded as an adjustment to
goodwill in the midstream segment.
 
 In
December 2006, ETP purchased a natural gas gathering system in north Texas for
$32.0 million in cash.  The purchase and sale agreement for the
gathering system in north Texas also had a contingent payment not to exceed
$21.0 million to be determined two years after the closing date.  In
December 2008, it was determined that a contingency payment would not be
required.  The gathering system consists of approximately 36 miles of
pipeline and has an estimated capacity of 70 MMcf/d.  We expect the
gathering system will allow us to continue expanding in the Barnett Shale area
of north Texas.  The cash paid for this acquisition was financed
primarily from advances under the previously existing credit
facility.
 
 During
the fiscal year ended August 31, 2007, HOLP and Titan collectively acquired
substantially all of the assets of five propane businesses.  The
aggregate purchase price for these acquisitions totaled $17.6 million, which
included $15.5 million of cash paid, net of cash acquired, and liabilities
assumed of $2.1 million.  The cash paid for acquisitions was financed
primarily with ETP’s and HOLP’s Senior Revolving Credit Facilities.
 
 Except
for the acquisition of the interests in ETP GP, the purchase of Class G Units
from ETP and the 50% member interests in CCEH, the acquisitions discussed above
were accounted for under the purchase method of accounting and the purchase
prices were allocated based on the estimated fair values of the assets acquired
and liabilities assumed at the date of the acquisition.  The
acquisition of the 50% member interest in CCEH was accounted for under the
equity method of accounting in accordance with APB Opinion No. 18, through
November 30, 2006.  The acquisition of 100% of Transwestern has been
accounted for under the purchase method of accounting since the acquisition on
December 1, 2006.  The acquisition of the interests in ETP GP was
accounted for on the basis of historical costs, as discussed
above.  The purchase of Class G Units from ETP was accounted for as
described in Note 7.
  28
  The
following table presents the allocation of the acquisition cost to the assets
acquired and liabilities assumed based on their fair values for the fiscal year
2007 acquisitions described above, net of cash acquired:
 
 Intrastate
      Transportation and Storage and Midstream Acquisitions (Aggregated)
              
              
              Transwestern
      Acquisition
              
              
              Propane
      Acquisitions (Aggregated)Accounts
      receivable
              
              $
              -
              
              
              $
              20,062
              
              
              $
              1,111Inventory
              
              
              -
              
              
              
              895
              
              
              
              414Prepaid
      and other current assets
              
              
              -
              
              
              
              11,842
              
              
              
              57Investment
      in unconsolidated affiliate
              
              
              (503
              )
              
              
              -
              
              
              
              -Property,
      plant, and equipment
              
              
              50,916
              
              
              
              1,254,968
              
              
              
              8,035Intangibles
      and other assets
              
              
              23,015
              
              
              
              141,378
              
              
              
              3,808Goodwill
              
              
              -
              
              
              
              107,550
              
              
              
              4,167Total
      assets acquired
              
              
              73,428
              
              
              
              1,536,695
              
              
              
              17,592Accounts
      payable
              
              
              -
              
              
              
              (1,932
              )
              
              
              (381
              )Customer
      advances and deposits
              
              
              -
              
              
              
              (700
              )
              
              
              (254
              )Accrued
      and other current liabilities
              
              
              (292
              )
              
              
              (33,149
              )
              
              
              (170
              )Short-term
      debt (paid in December 2006)
              
              
              -
              
              
              
              (13,000
              )
              
              
              -Long-term
      debt
              
              
              -
              
              
              
              (519,377
              )
              
              
              (1,309
              )Other
      long-term obligations
              
              
              -
              
              
              
              (10,096
              )
              
              
              -Total
      liabilities assumed
              
              
              (292
              )
              
              
              (578,254
              )
              
              
              (2,114
              )Net
      assets acquired
              
              $
              73,136
              
              
              $
              958,441
              
              
              $
              15,478
 
 The
purchase price for the acquisitions was initially allocated based on the
estimated fair value of the assets acquired and liabilities
assumed.  The Transwestern allocation was based on the preliminary
results of independent appraisals.  The purchase price allocations
were completed during the first quarter of 2008.  The final allocation
adjustments were not significant.
 
 Included
in the property, plant and equipment associated with the Transwestern
acquisition is an aggregate plant acquisition adjustment of $446.2 million,
which represents costs allocated to Transwestern’s transmission
plant.  This amount has not been included in the determination of
tariff rates Transwestern charges to its regulated customers.  The
unamortized balance of this adjustment was $419.6 million at December 31, 2008
and is being amortized over 35 years, the composite weighted average estimated
remaining life of Transwestern’s assets as of the acquisition date.
 
 Regulatory
assets, included in intangible and other assets on the consolidated balance
sheet, established in the Transwestern purchase price allocation consist of the
following:
 
 Accumulated
      reserve adjustment
              
              $
              42,132AFUDC
      gross-up
              
              
              9,280Environmental
      reserves
              
              
              6,623South
      Georgia deferred tax receivable
              
              
              2,593Cash
      Balance Plan
              
              
              9,329Total
      Regulatory Assets acquired
              
              $
              69,957
 
 All of
Transwestern’s regulatory assets are considered probable of recovery in
rates.
  29
  We
recorded the following intangible assets and goodwill in conjunction with the
fiscal year 2007 acquisitions described above:
 
 Intrastate
      Transportation and Storage and Midstream Acquisitions (Aggregated)
              
              
              Transwestern
      Acquisition
              
              
              Propane
      Acquisitions (Aggregated)Intangible
      assets:Contract
      rights and customer lists (6 to 15 years)
              
              $
              23,015
              
              
              $
              47,582
              
              
              $
              -Financing
      costs (7 to 9 years)
              
              
              -
              
              
              
              13,410
              
              
              
              -Other
              
              
              -
              
              
              
              -
              
              
              
              3,808Total
      intangible assets
              
              
              23,015
              
              
              
              60,992
              
              
              
              3,808Goodwill
              
              
              -
              
              
              
              107,550
              
              
              
              4,167Total
      intangible assets and goodwill acquired
              
              $
              23,015
              
              
              $
              168,542
              
              
              $
              7,975
 
 Goodwill
was warranted because these acquisitions enhance our current operations, and
certain acquisitions are expected to reduce costs through synergies with
existing operations.  We expect all of the goodwill acquired to be tax
deductible.  We do not believe that the acquired intangible assets
have any significant residual value at the end of their useful
life.
 
 4.
              INVESTMENTS IN
      AFFILIATES:
 
 Midcontinent
Express Pipeline LLC
 
 ETP is
party to an agreement with Kinder Morgan Energy Partners, L.P. (“KMP”) for a
50/50 joint development of the Midcontinent Express
pipeline.  Construction of the approximately 500-mile pipeline was
completed and natural gas transportation service commenced August 1, 2009 on the
pipeline from Delhi, Louisiana, to an interconnect with the Transco interstate
natural gas pipeline in Butler, Alabama.  Interim service began on the
pipeline from Bennington, Oklahoma, to Delhi in April 2009.  In July
2008, Midcontinent Express Pipeline LLC (“MEP”), the entity formed to construct,
own and operate this pipeline, completed an open season with respect to a
capacity expansion of the pipeline from the current capacity of 1.4 Bcf/d to a
total capacity of 1.8 Bcf/d for the main segment of the pipeline from north
Texas to an interconnect location with the Columbia Gas Transmission Pipeline
near Waverly, Louisiana.  The additional capacity was fully subscribed
as a result of this open season.  The planned expansion of capacity
will be added through the installation of additional compression on this segment
of the pipeline and is expected to be completed in the latter part of
2010.  This expansion was approved by the Federal Energy Regulatory
Commission (the “FERC”) in September 2009.
 
 On
January 9, 2009, MEP filed an amended application to revise its initial
transportation rates to reflect an increase in projected costs for the project;
the amended application was approved by the FERC on March 25, 2009.
 
 Fayetteville
Express Pipeline LLC
 
 ETP is
party to an agreement with KMP for a 50/50 joint development of the Fayetteville
Express pipeline, an approximately 185-mile natural gas pipeline that will
originate in Conway County, Arkansas, continue eastward through White County,
Arkansas and terminate at an interconnect with Trunkline Gas Company in Quitman
County, Mississippi.  In December 2009, Fayetteville Express Pipeline
LLC (“FEP”), the entity formed to construct, own and operate this pipeline,
received FERC approval of its application for authority to construct and operate
this pipeline.  That order is currently subject to a limited request
for rehearing.  The pipeline is expected to have an initial capacity
of 2.0 Bcf/d.  The pipeline project is expected to be in service by
the end of 2010.  FEP has secured binding 10-year commitments for
transportation of approximately 1.85 Bcf/d.  The new pipeline will
interconnect with Natural Gas Pipeline Company of America (“NGPL”) in White
County, Arkansas, Texas Gas Transmission in Coahoma County, Mississippi and ANR
Pipeline Company in Quitman County, Mississippi.  NGPL is operated and
partially owned by Kinder Morgan, Inc.  Kinder Morgan, Inc. owns the
general partner of KMP.
  30
  Capital
Contributions to Affiliates
 
 During
the year ended December 31, 2009, we contributed $664.5 million to
MEP.  FEP’s capital expenditures are being funded under a credit
facility.  All of our contributions to FEP were reimbursed to us in
2009, including $9.0 million that we contributed in 2008.
 
 Summarized
Financial Information
 
 The
following tables present aggregated selected balance sheet and income statement
data for our unconsolidated affiliates, MEP and FEP (on a 100%
basis):
 
 December 31,
                2009
              
              
              December 31,
                2008Current
      assets
              
              $
              33,794
              
              
              $
              9,953Property,
      plant and equipment, net
              
              
              2,576,031
              
              
              
              1,012,006Other
      assets
              
              
              19,658
              
              
              
              -Total
      assets
              
              $
              2,629,483
              
              
              $
              1,021,959Current
      liabilities
              
              $
              105,951
              
              
              $
              163,379Non-current
      liabilities
              
              
              1,198,882
              
              
              
              840,580Equity
              
              
              1,324,650
              
              
              
              18,000Total
      liabilities and equity
              
              $
              2,629,483
              
              
              $
              1,021,959
 
 
 Years Ended December 31,
              
              
              Four
      Months Ended December 31,
              
              
              Year
      Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Revenue
              
              $
              98,593
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -Operating
      income
              
              
              47,818
              
              
              
              -
              
              
              
              -
              
              
              
              -Net
      income
              
              
              36,555
              
              
              
              1,057
              
              
              
              -
              
              
              
              -
 
 As stated
above, MEP was placed into service during 2009.
 
 5.
              INCOME PER LIMITED
      PARTNER UNIT:
 
 Basic net
income per limited partner unit is computed by dividing net income, after
considering the General Partner’s interest, by the weighted average number of
limited partner interests outstanding.  Diluted net income per limited
partner unit is computed by dividing net income (as adjusted as discussed
herein), after considering the General Partner’s interest, by the weighted
average number of limited partner interests outstanding and the number of
unvested ETE Incentive Units granted.  For the diluted earnings per
share computation, income allocable to the limited partners is reduced, where
applicable, for the decrease in earnings from ETE’s limited partner unit
ownership in ETP that would have resulted assuming the incremental units related
to ETP’s equity incentive plans had been issued during the respective
periods.  Such units have been determined based on the treasury stock
method.
  31
  A
reconciliation of net income and weighted average units used in computing basic
and diluted net income per unit is as follows:
 
 Years Ended December 31,
              
              
              Four
      Months Ended December 31,
              
              
              Year
      Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Basic
      Net Income per Limited Partner Unit:Limited
      Partner’s interest in net income
              
              $
              441,103
              
              
              $
              373,883
              
              
              $
              92,390
              
              
              $
              318,312Weighted
      average limited partner units
              
              
              222,898,203
              
              
              
              222,829,956
              
              
              
              222,829,916
              
              
              
              204,578,719Basic
      net income per limited partner unit
              
              $
              1.98
              
              
              $
              1.68
              
              
              $
              0.41
              
              
              $
              1.56Diluted
      Net Income per Limited Partner Unit:Limited
      Partner’s interest in net income
              
              $
              441,103
              
              
              $
              373,883
              
              
              $
              92,390
              
              
              $
              318,312Dilutive
      effect of Unit Grants
              
              
              (410
              )
              
              
              (349
              )
              
              
              (218
              )
              
              
              (376
              )Diluted
      net income available to limited partners
              
              $
              440,693
              
              
              $
              373,534
              
              
              $
              92,172
              
              
              $
              317,936Weighted
      average limited partner units
              
              
              222,898,203
              
              
              
              222,829,956
              
              
              
              222,829,916
              
              
              
              204,578,719Diluted
      net income per limited partner unit
              
              $
              1.98
              
              
              $
              1.68
              
              
              $
              0.41
              
              
              $
              1.55
  32
  6.
              DEBT
      OBLIGATIONS:
 
 Our debt
obligations consist of the following:
 
 December 31,
                2009
              
              
              December 31,
                2008ETP
      Senior Notes:5.95%
      Senior Notes, due February 1, 2015
              
              $
              750,000
              
              
              $
              750,000
              
              Payable
      upon maturity. Interest is paid semi-annually.5.65%
      Senior Notes, due August 1, 2012
              
              
              400,000
              
              
              
              400,000
              
              Payable
      upon maturity. Interest is paid semi-annually.6.125%
      Senior Notes, due February 15, 2017
              
              
              400,000
              
              
              
              400,000
              
              Payable
      upon maturity. Interest is paid semi-annually.6.625%
      Senior Notes, due October 15, 2036
              
              
              400,000
              
              
              
              400,000
              
              Payable
      upon maturity. Interest is paid semi-annually.6.0%
      Senior Notes, due July 1, 2013
              
              
              350,000
              
              
              
              350,000
              
              Payable
      upon maturity. Interest is paid semi-annually.6.7%
      Senior Notes, due July 1, 2018
              
              
              600,000
              
              
              
              600,000
              
              Payable
      upon maturity. Interest is paid semi-annually.7.5%
      Senior Notes, due July 1, 2038
              
              
              550,000
              
              
              
              550,000
              
              Payable
      upon maturity. Interest is paid semi-annually.9.7%
      Senior Notes due March 15, 2019
              
              
              600,000
              
              
              
              600,000
              
              Put
      option on March 15, 2012. Payable upon maturity. Interest is paid
      semi-annually.8.5%
      Senior Notes due April 15, 2014
              
              
              350,000
              
              
              
              -
              
              Payable
      upon maturity. Interest is paid semi-annually.9.0%
      Senior Notes due April 15, 2019
              
              
              650,000
              
              
              
              -
              
              Payable
      upon maturity. Interest is paid semi-annually.Transwestern
      Senior Unsecured Notes:5.39%
      Senior Unsecured Notes, due November 17, 2014
              
              
              88,000
              
              
              
              88,000
              
              Payable
      upon maturity. Interest is paid semi-annually.5.54%
      Senior Unsecured Notes, due November 17, 2016
              
              
              125,000
              
              
              
              125,000
              
              Payable
      upon maturity. Interest is paid semi-annually.5.64%
      Senior Unsecured Notes, due May 24, 2017
              
              
              82,000
              
              
              
              82,000
              
              Payable
      upon maturity. Interest is paid semi-annually.5.89%
      Senior Unsecured Notes, due May 24, 2022
              
              
              150,000
              
              
              
              150,000
              
              Payable
      upon maturity. Interest is paid semi-annually.6.16%
      Senior Unsecured Notes, due May 24, 2037
              
              
              75,000
              
              
              
              75,000
              
              Payable
      upon maturity. Interest is paid semi-annually.5.36%
      Senior Unsecured Notes, due December 9, 2020
              
              
              175,000
              
              
              
              -
              
              Payable
      upon maturity. Interest is paid semi-annually.5.66%
      Senior Unsecured Notes, due December 9, 2024
              
              
              175,000
              
              
              
              -
              
              Payable
      upon maturity. Interest is paid semi-annually.HOLP
      Senior Secured Notes:8.55%
      Senior Secured Notes
              
              
              24,000
              
              
              
              36,000
              
              Annual
      payments of $12,000 due each June 30 through 2011.  Interest is
      paid semi-annually.Medium
      Term Note Program:7.17%
      Series A Senior Secured Notes
              
              
              -
              
              
              
              2,400
              
              Matured
      in November 2009.7.26%
      Series B Senior Secured Notes
              
              
              6,000
              
              
              
              8,000
              
              Annual
      payments of $2,000 due each November 19 through 2012.  Interest
      is paid semi-annually.Senior
      Secured Promissory Notes:8.55%
      Series B Senior Secured Notes
              
              
              4,571
              
              
              
              9,142
              
              Annual
      payments of $4,571 due each August 15 through 2010.  Interest is
      paid quarterly.8.59%
      Series C Senior Secured Notes
              
              
              5,750
              
              
              
              11,500
              
              Annual
      payments of $5,750 due each August 15 through 2010.  Interest is
      paid quarterly.8.67%
      Series D Senior Secured Notes
              
              
              33,100
              
              
              
              45,550
              
              Annual
      payments of $7,700 due August 15, 2010, $12,450 due August 15, 2011, and
      $12,950 due August 15, 2012.  Interest is paid
      quarterly.8.75%
      Series E Senior Secured Notes
              
              
              6,000
              
              
              
              7,000
              
              Annual
      payments of $1,000 due each August 15 through 2015.  Interest is
      paid quarterly.8.87%
      Series F Senior Secured Notes
              
              
              40,000
              
              
              
              40,000
              
              Annual
      payments of $3,636 due each August 15, 2010 through
      2020.  Interest is paid quarterly.7.89%
      Series H Senior Secured Notes
              
              
              5,091
              
              
              
              5,818
              
              Annual
      payments of $727 due each May 15 through 2016.  Interest is paid
      quarterly.7.99%
      Series I Senior Secured Notes
              
              
              16,000
              
              
              
              16,000
              
              One
      payment due May 15, 2013.  Interest is paid
      quarterly.Revolving
      Credit Facilities and Term Loans:ETE
      Senior Secured Revolving Credit Facility
              
              
              123,951
              
              
              
              121,642
              
              See
      terms below under “Parent Company  Credit
      Facilities”.ETE
      Senior Secured Term Loan
              
              
              1,450,000
              
              
              
              1,450,000
              
              See
      terms below under “Parent Company  Credit
      Facilities”.ETP
      Revolving Credit Facility
              
              
              150,000
              
              
              
              902,000
              
              See
      terms below under "ETP Credit Facility".HOLP
      Fourth Amended and Restated Senior Revolving Credit
    Facility
              
              
              10,000
              
              
              
              10,000
              
              See
      terms below under "HOLP Credit Facility".Other
      Long-Term Debt:Notes
      payable on noncompete agreements with interest imputed at rates averaging
      8.06% and 7.91% for December 31, 2009 and 2008,
    respectively
              
              
              7,898
              
              
              
              11,249
              
              Due
      in installments through 2014.Other
              
              
              2,390
              
              
              
              2,765
              
              Due
      in installments through 2024.Unamortized
      discounts
              
              
              (12,829
              )
              
              
              (13,477
              )7,791,922
              
              
              
              7,235,589Current
      maturities
              
              
              (40,924
              )
              
              
              (45,232
              )$
              7,750,998
              
              
              $
              7,190,357
  33
  Future
maturities of long-term debt for each of the next five years and thereafter are
as follows:
 
 2010
              
              $
              40,9242011
              
              
              168,5582012
              
              
              2,022,8812013
              
              
              372,5692014
              
              
              443,519Thereafter
              
              
              4,743,471$
              7,791,922
 
 ETP
Senior Notes
 
 The ETP
Senior Notes were registered under the Securities Act of 1933 (as
amended).  The Partnership may redeem some or all of the ETP Senior
Notes at any time, or from time to time, pursuant to the terms of the indenture
and related indenture supplements related to the ETP Senior
Notes.  Interest on the ETP Senior Notes is paid
semi-annually.
 
 The ETP
Senior Notes are unsecured obligations of ETP and the obligation of ETP to repay
the ETP Senior Notes is not guaranteed by us, ETP or any of ETP’s
subsidiaries.  As a result, the ETP Senior Notes effectively rank
junior to any future indebtedness of ours, ETP’s or its subsidiaries that is
both secured and unsubordinated to the extent of the value of the assets
securing such indebtedness, and the ETP Senior Notes effectively rank junior to
all indebtedness and other liabilities of ETP’s existing and future
subsidiaries.
 
 In April
2009, we completed a public offering of $350.0 million aggregate principal
amount of 8.5% Senior Notes due 2014 and $650.0 million aggregate principal
amount of 9.0% Senior Notes due 2019 (collectively the “2009 ETP
Notes”).  The offering of the 2009 ETP Notes closed on April 7, 2009
and we used net proceeds of approximately $993.6 million to repay borrowings
under the ETP Credit Facility and for general partnership
purposes.  Interest will be paid semi-annually.
 
 Transwestern
Senior Unsecured Notes
 
 Transwestern’s
long-term debt consists of $213.0 million remaining principal amount of notes
assumed in connection with the Transwestern acquisition, $307.0 million
aggregate principal amount of notes issued in May 2007, and $350.0 million
aggregate principal amount of notes issued in December 2009.  The
proceeds from the notes issued in December 2009 were used by Transwestern to
repay amounts under an intercompany loan agreement.  No principal
payments are required under any of the Transwestern notes prior to their
respective maturity dates.  The Transwestern notes rank pari passu
with Transwestern’s other unsecured debt.  The Transwestern notes are
payable at any time in whole or pro rata in part, subject to a premium or upon a
change of control event or an event of default, as defined.  Interest
is paid semi-annually.
 
 Transwestern’s
debt agreements contain certain restrictions that, among other things, limit the
incurrence of additional debt, the sale of assets and the payment of dividends
and specify a maximum debt to capitalization ratio.
 
 HOLP
Senior Secured Notes
 
 All
receivables, contracts, equipment, inventory, general intangibles, cash
concentration accounts, and the capital stock of HOLP and its subsidiaries
secure the HOLP Senior Secured, Medium Term, and Senior Secured Promissory Notes
(collectively, the “HOLP Notes”).
 
 Revolving
Credit Facilities
 
 Parent
Company Facilities
 
 The
Parent Company has a $1.45 billion Term Loan Facility and a Term Loan Maturity
Date of November 1, 2012 (the “Parent Company Credit Agreement”).  The
Parent Company Credit Agreement also includes a $500.0 million Secured Revolving
Credit Facility (the “Parent Company Revolving Credit Facility”) available
through February 8, 2011.  The Parent Company Revolving Credit
Facility includes a Swingline loan option with a maximum borrowing of $10.0
million and a daily rate based on LIBOR.
  34
  The total
outstanding amount borrowed under the Parent Company Credit Agreement and the
Parent Company Revolving Credit Facility as of December 31, 2009 was $1.57
billion.  The total amount available under the Parent Company’s debt
facilities as of December 31, 2009 was $376.0 million.  The Parent
Company Revolving Credit Facility also contains an accordion feature, which will
allow the Parent Company, subject to bank syndication’s approval, to expand the
facility’s capacity up to an additional $100.0 million.
 
 The
maximum commitment fee payable on the unused portion of the Parent Company
Revolving Credit Facility is based on the applicable Leverage Ratio, which is
currently at Level III or 0.375%.  Loans under the Parent Company
Revolving Credit Facility bear interest at Parent Company’s option at either (a)
the Eurodollar rate plus the applicable margin or (b) base rate plus the
applicable margin.  The applicable margins are a function of the
Parent Company’s leverage ratio that corresponds to levels set forth in the
agreement.  The applicable Term Loan bears interest at (a) the
Eurodollar rate plus 1.75% per annum and (b) with respect to any Base Rate Loan,
at Prime Rate plus 0.25% per annum.  As of December 31, 2009, the
weighted average interest rate was 1.94% for the amounts outstanding on the
Parent Company Senior Secured Revolving Credit Facility and the Parent Company
$1.45 billion Senior Secured Term Loan Facility.
 
 The
Parent Company Credit Agreement is secured by a lien on all tangible and
intangible assets of the Parent Company and its subsidiaries, including its
ownership of 62,500,797 ETP Common Units, the Parent Company’s 100% interest in
ETP LLC and ETP GP with indirect recourse to ETP GP’s General Partner interest
in ETP and 100% of ETP GP’s outstanding incentive distribution rights in ETP,
which the Parent Company holds through its ownership of ETP GP.
 
 ETP
Credit Facility
 
 The ETP
Credit Facility provides for $2.0 billion of revolving credit capacity that is
expandable to $3.0 billion (subject to obtaining the approval of the
administrative agent and securing lender commitments for the increased borrowing
capacity, under the Amended and Restated Credit Agreement).  The ETP
Credit Facility matures on July 20, 2012, unless we elect the option of one-year
extensions (subject to the approval of each such extension by the lenders
holding a majority of the aggregate lending commitments).  Amounts
borrowed under the ETP Credit Facility bear interest at a rate based on either a
Eurodollar rate or a prime rate.  The commitment fee payable on the
unused portion of the ETP Credit Facility varies based on our credit rating and
the fee is 0.11% based on our current rating with a maximum fee of
0.125%.
 
 As of
December 31, 2009, there was a balance outstanding in the ETP Credit Facility of
$150.0 million in revolving credit loans and approximately $62.2 million in
letters of credit.  The weighted average interest rate on the total
amount outstanding at December 31, 2009 was 0.78%.  The total amount
available under the ETP Credit Facility, as of December 31, 2009, which is
reduced by any letters of credit, was approximately $1.79
billion.  The indebtedness under the ETP Credit Facility is unsecured
and not guaranteed by any of the Partnership’s subsidiaries and has equal rights
to holders of our current and future unsecured debt.  The indebtedness
under the ETP Credit Facility has the same priority of payment as our other
current and future unsecured debt.
 
 HOLP
Credit Facility
 
 HOLP has
a $75.0 million Senior Revolving Facility (the “HOLP Credit Facility”) available
through June 30, 2011, which may be expanded to $150.0
million.  Amounts borrowed under the HOLP Credit Facility bear
interest at a rate based on either a Eurodollar rate or a prime
rate.  The commitment fee payable on the unused portion of the
facility varies based on the Leverage Ratio, as defined in the credit agreement
for the HOLP Credit Facility, with a maximum fee of 0.50%.  The
agreement includes provisions that may require contingent prepayments in the
event of dispositions, loss of assets, merger or change of
control.  All receivables, contracts, equipment, inventory, general
intangibles, cash concentration accounts of HOLP, and the capital stock of
HOLP’s subsidiaries secure the HOLP Credit Facility (total book value as of
December 31, 2009 of approximately $1.2 billion).  At December 31,
2009, there was $10.0 million outstanding in revolving credit loans and
outstanding letters of credit of $1.0 million.  The amount available
for borrowing as of December 31, 2009 was $64.0 million.
  35
  Covenants
Related to Our Credit Agreements
 
 The
agreements related to the ETP Senior Notes contain restrictive covenants
customary for an issuer with an investment-grade rating from the rating
agencies, which covenants include limitations on liens and a restriction on
sale-leaseback transactions.  The agreements and indentures related to
each of the Parent Company Revolving Credit Facility and Senior Secured Term
Loan Facility and ETP’s and the Operating Companies’ HOLP Notes and the HOLP
Credit Facility contain customary restrictive covenants applicable to the Parent
Company, ETP and the Operating Companies, including the maintenance of various
financial and leverage covenants, limitations on substantial disposition of
assets, changes in ownership, the level of additional indebtedness and creation
of liens as described in further detail below.
 
 The
Parent Company Revolving Credit Facility and Senior Secured Term Loan Facility
contain financial covenants as follows:
 
 ·
              Maximum
      Leverage Ratio – Consolidated Funded Debt of the Parent Company (as
      defined) to Consolidated EBITDA (as defined in the agreements) of the
      Parent Company of not more than 4.50 to 1.00, with a permitted increase to
      5.00 to 1.00 during a specified acquisition period extending for two
      fiscal quarters following the close of a specified
    acquisition
 
 ·
              Maximum
      Consolidated Leverage Ratio – Consolidated Funded Debt of the Parent
      Company and ETP to Consolidated EBITDA of ETP of not more than 5.50 to
      1.00
 
 ·
              Interest
      Coverage Ratio may not be less than 3.00 to
1.00
 
 ·
              Value
      to Loan Ratio may not be less than 2.00 to
1.00
 
 The
credit agreement relating to the ETP Credit Facility contains covenants that
limit (subject to certain exceptions) the Partnership’s and certain of the
Partnership’s subsidiaries, ability to, among other things:
 
 ·
              incur
      indebtedness;
 
 ·
              grant
      liens;
 
 ·
              enter
      into mergers;
 
 ·
              dispose
      of assets;
 
 ·
              make
      certain investments;
 
 ·
              make
      Distributions (as defined in such credit agreement) during certain
      Defaults (as defined in such credit agreement) and during any Event of
      Default (as defined in such credit
agreement);
 
 ·
              engage
      in business substantially different in nature than the business currently
      conducted by the Partnership and its
  subsidiaries;
 
 ·
              engage
      in transactions with affiliates;
 
 ·
              enter
      into restrictive agreements; and
 
 ·
              enter
      into speculative hedging contracts.
 
 The
credit agreement related to the ETP Credit Facility also contains a financial
covenant that provides that on each date ETP makes a distribution, the leverage
ratio, as defined in the ETP Credit Facility, shall not exceed 5.0 to 1, with a
permitted increase to 5.5 to 1 during a specified acquisition period, as defined
in the ETP Credit Facility.  This financial covenant could therefore
restrict ETP’s ability to make cash distributions to its Unitholders, its
general partner and the holder of its incentive distribution
rights.
 
 The
agreements related to the HOLP Notes and the HOLP Credit Facility contain
customary restrictive covenants applicable to HOLP, including the maintenance of
various financial and leverage covenants and limitations on substantial
disposition of assets, changes in ownership, the level of additional
indebtedness and creation of liens.  The financial covenants require
HOLP to maintain ratios of Adjusted Consolidated Funded Indebtedness to Adjusted
Consolidated EBITDA (as these terms are similarly defined in the agreements
related to the HOLP Notes and HOLP Credit Facility) of not more than 4.75 to 1
and Consolidated EBITDA to Consolidated Interest Expense (as these terms are
similarly defined in the agreements related to the HOLP Notes and HOLP Credit
Facility) of not less than 2.25 to 1.  These debt agreements also
provide that HOLP may declare, make, or incur a liability to make restricted
payments during each fiscal quarter, if: (a) the amount of such restricted
payment, together with all other restricted payments during such quarter, do not
exceed the amount of Available Cash (as defined in the agreements related to the
HOLP Notes and HOLP Credit Facility) with respect to the immediately preceding
quarter (which amount is required to reflect a reserve equal to 50% of the
interest to be paid on the HOLP Notes during the last quarter and in addition,
in the third, second and first quarters preceding a quarter in which a scheduled
principal payment is to be made on the HOLP Notes, and a reserve equal to 25%,
50%, and 75%, respectively, of the principal amount to be repaid on such payment
dates), (b) no default or event of default exists before such restricted
payments, and (c) the amounts of HOLP’s restricted payment is not
disproportionately greater than the payment amount from ETC OLP utilized to fund
payment obligations of ETP and its general partner with respect to ETP’s Common
Units.
  36
  Failure
to comply with the various restrictive and affirmative covenants of our
revolving credit facilities and the note agreements related to the HOLP Notes
could require us to pay debt balances prior to scheduled maturity and could
negatively impact the Operating Companies’ ability to incur additional debt
and/or our ability to pay distributions.
 
 We are
required to assess compliance quarterly and were in compliance with all
requirements, tests, limitations, and covenants related to our debt agreements
as of December 31, 2009.
 
 7.
              PARTNERS’
      CAPITAL:
 
 Limited
Partner Units
 
 Limited
partner interests in the Partnership are represented by Common Units that
entitle the holders thereof to the rights and privileges specified in the
Partnership Agreement.  The Partnership’s Common Units are registered
under the Securities Act of 1934 and are listed for trading on the New York
Stock Exchange (“NYSE”).  Each holder of a Common Unit is entitled to
one vote per unit on all matters presented to the Limited Partners for a
vote.  In addition, if at any time any person or group (other than the
Partnership’s General Partner and its affiliates) owns beneficially 20% or more
of all Common Units, any Common Units owned by that person or group may not be
voted on any matter and are not considered to be outstanding when sending
notices of a meeting of Unitholders (unless otherwise required by law),
calculating required votes, determining the presence of a quorum or for other
similar purposes under the Partnership Agreement.  The Common Units
are entitled to distributions of Available Cash as described below under
“Quarterly Distributions of Available Cash.”
 
 As of
December 31, 2009, there were issued and outstanding 222,898,248 Common Units
representing an aggregate 99.69% limited partner interest in the
Partnership.
 
 Our
Partnership Agreement contains specific provisions for the allocation of net
earnings and losses to the partners for purposes of maintaining the partner
capital accounts.  For any fiscal year that the Partnership has net
profits, such net profits are first allocated to the General Partner until the
aggregate amount of net profits for the current and all prior fiscal years
equals the aggregate amount of net losses allocated to the General Partner for
the current and all prior fiscal years.  Second, such net profits
shall be allocated to the Limited Partners pro rata in accordance with their
respective sharing ratios.  For any fiscal year in which the
Partnership has net losses, such net losses shall be first allocated to the
Limited Partners in proportion to their respective adjusted capital account
balances, as defined by the Partnership Agreement, (before taking into account
such net losses) until their adjusted capital account balances have been reduced
to zero.  Second, all remaining net losses shall be allocated to the
General Partner.  The General Partner may distribute to the Limited
Partners funds of the Partnership that the General Partner reasonably determines
are not needed for the payment of existing or foreseeable Partnership
obligations and expenditures.
 
 In
connection with our initial public offering in February 2006, we issued Class B
Units to our management, and all of the Class B Units were converted to ETE
Common Units in March 2007.  In November 2006, we issued Class C Units
to acquire limited partner interest in ETP GP, and in February 2007, all of the
Class C Units were converted to ETE Common Units.
  37
  Common
Units
 
 The
change in Common Units is as follows:
 
 Years Ended
    December 31,
              
              
              Four Months Ended
      December 31,
              
              
              Year Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Number
      of Units, beginning of period
              
              
              222,829,956
              
              
              
              222,829,956
              
              
              
              222,828,332
              
              
              
              124,360,520Issuance
      of restricted Common Units under long-term incentive plan
              
              
              68,292
              
              
              
              -
              
              
              
              1,624
              
              
              
              1,948Issuance
      of Common Units
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              12,795,394Conversion
      of Class B Units to Common Units
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              2,521,570Conversion
      of Class C Units to Common Units
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              83,148,900Number
      of Units, end of period
              
              
              222,898,248
              
              
              
              222,829,956
              
              
              
              222,829,956
              
              
              
              222,828,332
 
 Sale
of Common Units by Subsidiary
 
 The
Parent Company accounts for the difference between the carrying amount of its
investment in ETP and the underlying book value arising from issuance of units
by ETP (excluding unit issuances to the Parent Company) as a capital
transaction.  The capital transactions are reflected in the
Partnership’s consolidated balance sheets as an increase in partners’
capital.  If ETP issues units at a price less than the Parent
Company’s carrying value per unit, the Parent Company assesses whether the
investment in ETP has been impaired, in which case a provision would be
reflected in the statement of operations.  The Parent Company did not
recognize any impairment related to the issuance of ETP Common Units during the
periods presented.
 
 On
November 1, 2006, the Parent Company purchased 26,086,957 Class G Units
representing limited partnership interests in ETP.  The price per unit
paid for each of the Common Units was equal to $46.00 per unit, based upon a
market discount from the NYSE closing price of the ETP’s Common Units on October
31, 2006 of $48.94.  ETP used a portion of the proceeds to purchase
interests in CCEH (see Note 3).  On May 1, 2007, the Unitholders of
ETP approved the conversion of the Class G Units to Common Units and all the
outstanding ETP Class G Units converted to ETP Common Units on a one-for-one
basis on such date.  The Parent Company recorded the premium of $451.2
million (the difference between the Parent Company’s share of the underlying
book value in ETP before and after the purchase of the Class G Units) as a
reduction of the Parent Company’s limited partners’ capital with a corresponding
increase in minority interest.
 
 The
following table summarizes ETP’s public offerings of ETP Common
Units:
 
 Date
              
              Number of Common Units (1)
              
              
              Price per Unit
              
              
              Net Proceeds
              
              
              Use of ProceedsDecember
      2007 (2)
              
              
              5,750,000
              
              
              $
              48.81
              
              
              $
              269.4
              
              
              
              (3)July
      2008
              
              
              8,912,500
              
              
              
              39.45
              
              
              
              337.5
              
              
              
              (4)January
      2009
              
              
              6,900,000
              
              
              
              34.05
              
              
              
              225.4
              
              
              
              (4)April
      2009
              
              
              9,775,000
              
              
              
              37.55
              
              
              
              352.4
              
              
              
              (5)October
      2009
              
              
              6,900,000
              
              
              
              41.27
              
              
              
              276.0
              
              
              
              (4)January
      2010
              
              
              9,775,000
              
              
              
              44.72
              
              
              
              423.6
              
              
              
              (4)(5)
 
 ___________
 (1)
              Number
      of Common Units includes the exercise of the overallotment options by the
      underwriters.
 (2)
              Amounts
      include the exercise of the overallotment option by the underwriters in
      January 2008.
 (3)
              Proceeds
      were used to repay amounts outstanding under ETP's prior term loan
      facility.
 (4)
              Proceeds
      were used to repay amounts outstanding under the ETP Credit
      Facility.
 (5)
              Proceeds
      were used to fund capital expenditures and capital contributions to joint
      ventures, as
      well as for general partnership
purposes.
   38
  On August
26, 2009, ETP entered into an Equity Distribution Agreement with UBS Securities
LLC (“UBS”).  Pursuant to this agreement, ETP may offer and sell from
time to time through UBS, as their sales agent, ETP Common Units having an
aggregate offering price of up to $300.0 million.  Sales of the units
will be made by means of ordinary brokers’ transactions on the NYSE at market
prices, in block transactions or as otherwise agreed between ETP and
UBS.  Under the terms of this agreement, ETP may also sell ETP Common
Units to UBS as principal for its own account at a price agreed upon at the time
of sale.  Any sale of ETP Common Units to UBS as principal would be
pursuant to the terms of a separate agreement between ETP and
UBS.  During 2009, ETP issued 2,079,593 ETP Common Units pursuant to
this agreement 1,891,691 of which have been settled as of December 31,
2009.  The proceeds of approximately $81.5 million, net of
commissions, were used to repay amounts outstanding under the ETP Credit
Facility.
 
 As a
result of ETP’s issuance of ETP Common Units, we have recognized increases in
partner’s capital of $97.0 million and $48.8 million for the years ended
December 31, 2009 and 2008, respectively, and $48.9 million for the four months
ended December 31, 2007.
 
 Contributions
to Subsidiary
 
 The
Parent Company indirectly owns the entire general partner interest in ETP
through its ownership of ETP GP, the general partner of ETP.  In order
to maintain its general partner interest in ETP, ETP GP has previously been
required to make contributions to ETP each time ETP issues limited partner
interests for cash or in connection with acquisitions.  These
contributions are generally paid by offsetting the required contributions
against the funds ETP GP receives from ETP distributions on the general partner
and limited partner interests owned by ETP GP.  ETP GP was required to
contribute approximately $12.3 million and $8.0 million for the years ended
December 31, 2009 and 2008, $5.0 million for the four months ended December 31,
2007, and $24.5 million for the year ended August 31, 2007,
respectively.  As of December 31, 2009, ETP GP has a contribution
payable to ETP of $8.9 million.
 
 In July
2009, ETP amended and restated its partnership agreement, and as a result, ETP
GP is no longer required to make corresponding contributions to maintain its
general partner interest in ETP.
 
 Parent
Company Quarterly Distributions of Available Cash
 
 Our
distribution policy is consistent with the terms of our Partnership Agreement,
which requires that we distribute all of our available cash
quarterly.  We currently have no independent operations outside of our
interests in ETP.
 
 Our only
cash-generating assets currently consist of distributions from ETP related to
the following limited and general partner interests, including incentive
distribution rights in ETP:
 
 ·
              ETE’s
      ownership of the general partner interest in ETP, which it holds through
      its ownership interests in ETP GP.
 
 ·
              62,500,797
      ETP Common Units, which ETE holds directly, representing approximately 35%
      of the total outstanding ETP Common Units as of December 31, 2009,
      and
 
 ·
              100%
      of the incentive distribution rights in ETP, which ETE holds through its
      ownership interests in ETP GP and which entitle it to receive specified
      percentages of the cash distributed by ETP as ETP’s per unit distribution
      increases.  The Parent Company’s incentive distribution rights
      entitle it to receive incentive distributions to the extent that quarterly
      distributions to ETP’s Unitholders exceed $0.275 per unit ($1.10 per unit
      on an annualized basis).  These incentive distributions entitle
      the Parent Company to increasing percentages of ETP’s cash distributions
      based upon exceeding incentive distribution thresholds specified in ETP’s
      Partnership Agreement, which incentive distribution rights entitle the
      Parent Company to receive 48% of ETP’s cash distributions in excess of
      $0.4125 per unit.  At ETP’s current distribution levels, the
      Parent Company is entitled to receive cash distributions at the highest
      incentive distribution level of 48% with respect to ETP’s distributions in
      excess of $0.4125 per unit.
  39
  Our
distributions declared during the years ended December 31, 2009 and 2008, the
four months ended December 31, 2007 and the year ended August 31, 2007 are
summarized as follows:
 
 Record Date
              
              Payment Date
              
              Amount per UnitCalendar
      Year Ended December 31, 2009
              November
      9, 2009
              
              November
      19, 2009
              
              $
              0.5350August
      7, 2009
              
              August
      19, 2009
              
              
              0.5350May
      8, 2009
              
              May
      19, 2009
              
              
              0.5250February
      6, 2009
              
              February
      19, 2009
              
              
              0.5100Calendar
      Year Ended December 31, 2008
              November
      10, 2008
              
              November
      19, 2008
              
              $
              0.4800August
      7, 2008
              
              August
      19, 2008
              
              
              0.4800May
      5, 2008
              
              May
      19, 2008
              
              
              0.4400February
      1, 2008 (1)
              
              February
      19, 2008
              
              
              0.5500Transition
      Period Ended December 31, 2007
              October
      5, 2007
              
              October
      19, 2007
              
              $
              0.3900Fiscal
      Year Ended August 31, 2007
              July
      2, 2007
              
              July
      19, 2007
              
              $
              0.3725April
      9, 2007
              
              April
      16, 2007
              
              
              0.3560January
      4, 2007
              
              January
      19, 2007
              
              
              0.3400October
      5, 2006
              
              October
      19, 2006
              
              
              0.3125
 
 (1)
              One-time
      four month distribution – On January 18, 2008, our Board of Directors
      approved the management recommendation for a one-time four-month
      distribution for our Unitholders to complete the conversion to a calendar
      year end from the previous August 31 fiscal year end.  ETE’s
      distribution amount related to the four months ended December 31, 2007 was
      $0.55 per Common Unit, representing a distribution of $0.41 per unit for
      the three-month period and $0.14 per unit for the additional
      month.
 
 The total
amount of distributions we have declared is as follows (all from Available Cash
from our operating surplus and are shown in the period to which they
relate):
 
 Years Ended
    December 31,
              
              
              Four
      Months Ended December 31,
              
              
              Year
      Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Limited
      Partners -Common
      Units
              
              $
              475,911
              
              
              $
              425,640
              
              
              $
              122,556
              
              
              $
              294,175Class
      B Units
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              857Class
      C Units
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              28,261General
      Partner
              
              
              1,478
              
              
              
              1,322
              
              
              
              381
              
              
              
              1,009Total
      distributions declared
              
              $
              477,389
              
              
              $
              426,962
              
              
              $
              122,937
              
              
              $
              324,302
 
 On
January 28, 2010, the Parent Company declared a cash distribution for the fourth
quarter ended December 31, 2009 of $0.54 per Common Unit, or $2.16
annualized.  We paid this distribution on February 19, 2010 to
Unitholders of record at the close of business on February 8, 2010.
 
 ETP’s
Quarterly Distribution of Available Cash
 
 ETP’s
Partnership Agreement requires that ETP distribute all of its Available Cash to
its Unitholders and its General Partner within 45 days following the end of each
fiscal quarter, subject to the payment of incentive distributions to the holders
of IDRs to the extent that certain target levels of cash distributions are
achieved.  The term Available Cash generally means, with respect to
any fiscal quarter of ETP, all cash on hand at the end of such quarter, plus
working capital borrowings after the end of the quarter, less reserves
established by its General Partner in its sole discretion to provide for the
proper conduct of ETP’s business, to comply with applicable laws or any debt
instrument or other agreement, or to provide funds for future distributions to
partners with respect to any one or more of the next four
quarters.  Available Cash is more fully defined in ETP’s Partnership
Agreement.
  40
  ETP’s
distributions declared during the periods presented below are summarized as
follows:
 
 Record Date
              
              Payment Date
              
              Amount per UnitCalendar
      Year Ended December 31, 2009
              November
      9, 2009
              
              November
      16, 2009
              
              $
              0.89375August
      7, 2009
              
              August
      14, 2009
              
              
              0.89375May
      8, 2009
              
              May
      15, 2009
              
              
              0.89375February
      6, 2009
              
              February
      13, 2009
              
              
              0.89375Calendar
      Year Ended December 31, 2008
              November
      10, 2008
              
              November
      14, 2008
              
              $
              0.89375August
      7, 2008
              
              August
      14, 2008
              
              
              0.89375May
      5, 2008
              
              May
      15, 2008
              
              
              0.86875February
      1, 2008 (1)
              
              February
      14, 2008
              
              
              1.12500Transition
      Period Ended December 31, 2007
              October
      5, 2007
              
              October
      15, 2007
              
              $
              0.82500Fiscal
      Year Ended August 31, 2007
              July
      2, 2007
              
              July
      16, 2007
              
              $
              0.80625April
      6, 2007
              
              April
      13, 2007
              
              
              0.78750January
      4, 2007
              
              January
      15, 2007
              
              
              0.76875October
      5, 2006
              
              October
      16, 2006
              
              
              0.75000
 
 (1)
              One-time
      four month distribution – On January 18, 2008 ETP’s Board of Directors
      approved the management recommendation for a one-time four-month
      distribution for ETP Unitholders to complete the conversion to a calendar
      year end from the previous August 31 fiscal year end.  ETP’s
      distribution amount related to the four months ended December 31, 2007 was
      $1.125 per Common Unit, representing a distribution of $0.84375 per unit
      for the three-month period and $0.28125 per unit for the additional
      month.
 
 The total
amount of distributions the Parent Company received from ETP relating to its
limited partner interests, general partner interests and incentive distribution
rights of ETP are as follows (shown in the period to which they
relate):
 
 Years Ended
    December 31,
              
              
              Four
      Months Ended December 31,
              
              
              Year
      Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Limited
      Partners Interests
              
              $
              223,440
              
              
              $
              221,878
              
              
              $
              70,313
              
              
              $
              199,221General
      Partner Interest
              
              
              19,505
              
              
              
              17,322
              
              
              
              5,110
              
              
              
              13,705Incentive
      Distribution Rights
              
              
              350,486
              
              
              
              298,575
              
              
              
              85,775
              
              
              
              222,353Total
      distributions received from ETP
              
              $
              593,431
              
              
              $
              537,775
              
              
              $
              161,198
              
              
              $
              435,279
 
 The total
amounts of ETP distributions declared during the periods presented in the
consolidated financial statements are as follows (all from Available Cash from
ETP’s operating surplus and are shown in the period to which they
relate):
 
 Years Ended
    December 31,
              
              
              Four
      Months Ended December 31,
              
              
              Year
      Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Limited
      Partners -Common
      Units
              
              $
              629,263
              
              
              $
              537,731
              
              
              $
              160,672
              
              
              $
              396,095Class
      E Units
              
              
              12,484
              
              
              
              12,484
              
              
              
              3,121
              
              
              
              12,484Class
      G Units
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              40,598General
      Partner Interest
              
              
              19,505
              
              
              
              17,322
              
              
              
              5,110
              
              
              
              13,705Incentive
      Distribution Rights
              
              
              350,486
              
              
              
              298,575
              
              
              
              85,775
              
              
              
              222,353$
              1,011,738
              
              
              $
              866,112
              
              
              $
              254,678
              
              
              $
              685,235
  41
  Upon
their conversion to ETP Common Units, all the ETP Class G Units ceased to have
the right to participate in ETP distributions of available cash from operating
surplus as itemized above.
 
 On
January 28, 2010, ETP declared a cash distribution for the fourth quarter ended
December 31, 2009 of $0.89375 per Common Unit, or $3.575
annualized.  ETP paid this distribution on February 15, 2010 to
Unitholders of record at the close of business on February 8, 2010.
 
 Accumulated
Other Comprehensive Income
 
 The
following table presents the components of AOCI, net of tax:
 
 December 31,
                2009
              
              
              December 31,
                2008Net
      gain on commodity related hedges
              
              $
              1,991
              
              
              $
              8,735Net
      loss on interest rate hedges
              
              
              (56,210
              )
              
              
              (68,896
              )Unrealized
      gains (losses) on available-for-sale securities
              
              
              4,941
              
              
              
              (5,983
              )Noncontrolling
      interest
              
              
              (4,350
              )
              
              
              (1,681
              )Total
      AOCI, net of tax
              
              $
              (53,628
              )
              
              $
              (67,825
              )
 
 8.
              UNIT-BASED
      COMPENSATION PLANS:
 
 We
recognized non-cash unit-based compensation expense related to the unit-based
compensation plans of ETP and ETE of $24.6 million and $24.3 million for the
years ended December 31, 2009 and 2008, $8.1 million for the four months ended
December 31, 2007, and $10.5 million for the year ended August 31, 2007,
respectively.
 
 ETE
Long-Term Incentive Plan
 
 Concurrently
with the IPO during the second quarter of fiscal year 2006, 2,521,570 Class B
Units were issued to McReynolds Equity Partners, L.P., the general partner of
which is owned and controlled by John W. McReynolds.  On March 27,
2007, the Class B Units were converted to Common Units.
 
 In
addition, the Board of Directors or the Compensation Committee of the board of
directors of the Partnership’s general partner (the “Compensation Committee”)
may from time to time grant additional awards to employees, directors and
consultants of ETE’s general partner and its affiliates who perform services for
ETE.  The plan provides for the following five types of awards:
restricted units, phantom units, unit options, unit appreciation rights and
distribution equivalent rights.  The number of additional units that
may be delivered pursuant to these awards is limited to 3,000,000 units,
excluding the Class B Units discussed above.  As of December 31, 2009,
2,887,136 units remain available to be awarded under the plan.
 
 During
2009 and 2008, the Compensation Committee granted a total of 41,000 and 65,000
ETE units with grant date fair values of $16.64 and $30.76 per unit,
respectively, to employees with vesting over a five-year period at 20% per
year.  These awards include rights to distributions paid on unvested
units.
 
 On
December 22, 2006, the Compensation Committee voted to award each ETE Director
who is not also (i) a shareholder or a direct or indirect employee of any
parent, or (ii) a direct or indirect employee of ETP LLC, ETP, or a subsidiary
(“Director Participant”), who is then in office and, automatically on the first
day of the fiscal year thereafter, an award of Units equal to $15 thousand
divided by the fair market value of ETE Common Units on such date (“Annual
Director’s Grant”).  Each award to a Director Participant will vest at
the rate of one third per year, beginning on the first anniversary date of the
Award; provided however, notwithstanding the foregoing, all awards to a Director
Participant shall become fully vested upon a change in control, as defined by
the 2004 Unit Plan.  During 2009, a total of 14,192 ETE units vested,
with a total fair value of $0.4 million.  As of December 31, 2009, a
total of 96,836 restricted units granted to ETE employees and directors remain
outstanding, for which we expect to recognize a total of $1.9 million in
compensation over a weighted average period of 2.7 years.
 
 ETP
Unit-Based Compensation Plans
 
 ETP has
issued equity awards to employees and directors under the following
plans:
  42
  ·
              2008
      Long-Term Incentive Plan.On
      December 16, 2008, ETP Unitholders approved the ETP 2008 Long-Term
      Incentive Plan (the “ETP 2008 Incentive Plan”), which provides for awards
      of options to purchase ETP Common Units, awards of restricted units,
      awards of phantom units, awards of Common Units, awards of distribution
      equivalent rights (“DERs”), awards of Common Unit appreciation rights, and
      other unit-based awards to employees of ETP, ETP GP, ETP LLC, a subsidiary
      or their affiliates, and members of ETP LLC’s board of directors, which we
      refer to as the board of directors.  Up to 5,000,000 ETP Common
      Units may be granted as awards under the ETP 2008 Incentive Plan, with
      such amount subject to adjustment as provided for under the terms of the
      ETP 2008 Incentive Plan.  The ETP 2008 Incentive Plan is
      effective until December 16, 2018 or, if earlier, the time which all
      available units under the ETP 2008 Incentive Plan have been issued to
      participants or the time of termination of the plan by the board of
      directors.  As of December 31, 2009, a total of 4,213,111 ETP
      Common Units remain available to be awarded under the ETP 2008 Incentive
      Plan.
 
 ·
              2004 Unit
      Plan.ETP’s
      Amended and Restated 2004 Unit Award Plan (the “ETP 2004 Unit Plan”)
      provides for awards of up to 1,800,000 ETP Common Units and other rights
      to its employees, officers and directors.  Any awards that are
      forfeited or which expire for any reason or any units, which are not used
      in the settlement of an award, will be available for grant under the ETP
      2004 Unit Plan.  As of December 31, 2009, 5,578 ETP Common Units
      were available for future grants under the ETP 2004 Unit
    Plan.
 
 ETP
Employee Grants
 
 Prior to
December 2007, substantially all of the awards granted to employees required the
achievement of performance objectives in order for the awards to become
vested.  The expected life of each unit award subject to the
achievement of performance objectives is assumed to be the minimum vesting
period under the performance objectives of such unit
award.  Generally, each award was structured to provide that, if the
performance objectives related to such award are achieved, one-third of the
units subject to such award will vest each year over a three-year period with
100% of such one-third vesting if the total return for the ETP units for such
year is in the top quartile as compared to a peer group of energy-related
publicly traded limited partnerships determined by the Compensation Committee,
65% of such one-third vesting if the total return of the ETP units for such year
is in the second quartile as compared to such peer group companies, and 25% of
such one-third vesting if the total return of the ETP units for such year is in
the third quartile as compared to such peer group companies.  Total
return is defined as the sum of the per unit price appreciation in the market
price of the ETP units for the year plus the aggregate per unit cash
distributions received for the year.  Non-cash compensation expense is
recorded for these ETP awards based upon the total awards granted over the
required service period that are expected to vest based on the estimated level
of achievement of performance objectives.  As circumstances change,
cumulative adjustments of previously-recognized compensation expense are
recorded.
 
 In
October 2008, the Compensation Committee determined that, of the unit awards
subject to the achievement of performance objectives, 25% of the ETP Common
Units subject to such awards eligible to vest on September 1, 2007 became vested
and 75% of the awards were forfeited based on ETP’s performance for the
twelve-month period ended August 31, 2008.  In October 2008, the
Compensation Committee approved a special grant of the new unit awards that
entitled each holder to receive a number of ETP Common Units equal to the number
of ETP Common Units forfeited as of September 1, 2007, which new unit awards
became fully vested on October 15, 2008.  These Compensation Committee
actions affected all ETP employee unit awards including unit awards granted to
ETP’s executive officers.
 
 Commencing
in December 2007, ETP has also granted restricted unit awards to employees that
vest over a specified time period, with vesting based on continued employment as
of each applicable vesting date without regard to the satisfaction of any
performance objectives.  Upon vesting, ETP Common Units are
issued.  The unit awards under ETP’s equity incentive plans generally
require the continued employment of the recipient during the vesting period;
however, the Compensation Committee has complete discretion to accelerate the
vesting of unvested unit awards.
 
 In 2008
and 2009, the Compensation Committee approved the grant of new unit awards,
which vest over a five-year period at 20% per year, subject to continued
employment through each specified vesting date.  These unit awards
entitle the recipients of the unit awards to receive, with respect to each ETP
Common Unit subject to such award that has not either vested or been forfeited,
a cash payment equal to each cash distribution per ETP Common Unit made by ETP
on its Common Units promptly following each such distribution by ETP to its
Unitholders.  We refer to these rights as “distribution equivalent
rights.”
  43
  Prior to
2008 and 2009, units were generally awarded without distribution equivalent
rights.  For such awards, ETP calculated the grant-date fair value
based on the market value of the underlying units, reduced by the present value
of the distributions expected to be paid on the units during the requisite
service period.  The present value of expected service period
distributions is computed based on the risk-free interest rate, the expected
life of the unit grants and the distribution yield at that time.
 
 Director
Grants
 
 Under
ETP’s equity incentive plans, ETP’s non-employee directors each receive unvested
ETP Common Units with a grant-date fair value of $50,000 each
year.  These non-employee director grants vest ratably over three
years and do not entitle the holders to receive distributions during the vesting
period.
 
 Award
Activity
 
 The
following table shows the activity of the ETP awards granted to employees and
non-employee directors:
 
 Number
      of Units
              
              
              Weighted
      Average Grant-Date Fair Value Per
      UnitUnvested
      awards as of December 31, 2008
              
              
              1,372,568
              
              
              $
              36.83Awards
      granted
              
              
              763,190
              
              
              
              43.56Awards
      vested
              
              
              (336,386
              )
              
              
              36.02Awards
      forfeited
              
              
              (108,780
              )
              
              
              39.17Unvested
      awards as of December 31, 2009
              
              
              1,690,592
              
              
              
              39.88
 
 The
balance above for unvested awards as of December 31, 2008 includes 150,852 unit
awards with a grant-date fair value of $43.96 per unit, which were granted prior
to 2008 and were subject to a performance condition, as described
above.  These remaining performance awards vested in 2009, and none of
the unvested unit awards outstanding as of December 31, 2009 contain performance
conditions.
 
 During
the years ended December 31, 2009 and 2008, the four months ended December 31,
2007 and the year ended August 31, 2007, the weighted average grant-date fair
value per unit award granted was $43.56, $33.86, $42.46 and $43.73,
respectively.  The total fair value of awards vested was $14.7
million, $14.6 million, $3.3 million and $7.9 million, respectively based on the
market price of ETP Common Units as of the vesting date.  As of
December 31, 2009, a total of 1,690,592 unit awards remain unvested, for which
ETP expects to recognize a total of $50.9 million in compensation expense over a
weighted average period of 1.9 years.
 
 Related Party
Awards
 
 McReynolds
Energy Partners, L.P., the general partner of which is owned and controlled by
an ETE officer, awarded to certain officers of ETP certain rights related to
units of ETE previously issued by ETE to such officer.  These rights
include the economic benefits of ownership of these ETE units based on a five
year vesting schedule whereby the officer will vest in the ETE units at a rate
of 20% per year.  As these ETE units are conveyed to the recipients of
these awards upon vesting from a partnership that is not owned or managed by ETE
or ETP, none of the costs related to such awards are paid by ETP or ETE unless
this partnership defaults under its obligations pursuant to these unit
awards.  As these units were outstanding prior to these awards, these
awards do not represent an increase in the number of outstanding units of either
ETP or ETE and are not dilutive to cash distributions per unit with respect to
either ETP or ETE.
 
 During
the years ended December 31, 2008 and August 31, 2007, unvested rights related
to 450,000 ETE common units and 675,000 ETE common units, respectively, with
aggregate grant-date fair values of $10.3 million and $23.5 million,
respectively, were awarded to ETP officers.  During the year ended
December 31, 2008, unvested rights related to 240,000 ETE common units were
forfeited.  During the years ended December 31, 2009 and 2008 and the
four months ended December 31, 2007, ETP officers vested in rights related to
165,000 ETE common units, 135,000 ETE common units, and 55,000 ETE common units,
respectively, with aggregate fair values upon vesting of $4.6 million, $3.5
million, and $1.9 million, respectively.
  44
  ETP is
recognizing non-cash compensation expense over the vesting period based on the
grant-date fair value of the ETE units awarded the ETP employees assuming no
forfeitures.  For the years ended December 31, 2009 and 2008, the four
months ended December 31, 2007, and the fiscal year ended August 31, 2007, ETP
recognized non-cash compensation expense, net of forfeitures, of
$6.4  million, $3.5 million, $3.6 million, and $5.2 million,
respectively, as a result of these awards.
 
 As of
December 31, 2009, rights related to 530,000 ETE common units remain
outstanding, for which we expect to recognize a total of $6.8 million in
compensation expense over a weighted average period of 1.9 years
 
 9.
              INCOME
      TAXES:
 
 The
components of the federal and state income tax provision (benefit) of our
taxable subsidiaries are summarized as follows:
 
 Years Ended
    December 31,
              
              
              Four
      Months Ended December 31,
              
              
              Year
      Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Current
      provision:Federal
              
              $
              (8,850
              )
              
              $
              (180
              )
              
              $
              2,990
              
              
              $
              7,896State
              
              
              9,657
              
              
              
              12,241
              
              
              
              5,831
              
              
              
              10,432Total
              
              
              807
              
              
              
              12,061
              
              
              
              8,821
              
              
              
              18,328Deferred
      provision:Federal
              
              
              8,643
              
              
              
              (8,531
              )
              
              
              516
              
              
              
              (7,494
              )State
              
              
              (221
              )
              
              
              278
              
              
              
              612
              
              
              
              557Total
              
              
              8,422
              
              
              
              (8,253
              )
              
              
              1,128
              
              
              
              (6,937
              )Total
      tax provision
              
              $
              9,229
              
              
              $
              3,808
              
              
              $
              9,949
              
              
              $
              11,391
 
 On May
18, 2006, the State of Texas enacted House Bill 3, which replaced the existing
state franchise tax with a “margin tax”.  In general, legal entities
that conduct business in Texas are subject to the Texas margin tax, including
previously non-taxable entities such as limited partnerships and limited
liability partnerships.  The tax is assessed on Texas sourced taxable
margin, which is defined as the lesser of (i) 70% of total revenue or (ii) total
revenue less (a) cost of goods sold or (b) compensation and
benefits.  Although the bill states that the margin tax is not an
income tax, it has the characteristics of an income tax since it is determined
by applying a tax rate to a base that considers both revenues and
expenses.  Therefore, we have accounted for Texas margin tax as income
tax expense in the period subsequent to the law’s effective date of January 1,
2007.  For the years ended December 31, 2009 and 2008, the four months
ended December 31, 2007, and the fiscal year ended August 31, 2007, we
recognized current state income tax expense related to the Texas margin tax of
$8.5 million, $10.5 million, $3.9 million and $6.9 million,
respectively.
 
 The
effective tax rate differs from the statutory rate due primarily to Partnership
earnings that are not subject to federal and state income taxes at the
Partnership level.  The difference between the statutory rate and the
effective rate is summarized as follows:
 
 Years Ended
    December 31,
              
              
              Four
      Months Ended December 31,
              
              
              Year
      Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Federal
      statutory tax rate
              
              
              35.00
              %
              
              
              35.00
              %
              
              
              35.00
              %
              
              
              35.00
              %State
      income tax rate net of federal benefit
              
              
              1.08
              %
              
              
              1.59
              %
              
              
              2.57
              %
              
              
              1.25
              %Earnings
      not subject to tax at the Partnership level
              
              
              (34.77
              %)
              
              
              (36.03
              %)
              
              
              (32.41
              %)
              
              
              (34.23
              %)Effective
      tax rate
              
              
              1.31
              %
              
              
              0.56
              %
              
              
              5.16
              %
              
              
              2.02
              %
  45
  Deferred
income taxes reflect the net tax effects of temporary differences between the
carrying amounts of assets and liabilities for financial reporting purposes and
the amounts used for income tax purposes.  The components of the
deferred tax liability were as follows:
 
 December 31,
              
              
              December 31,2009
              
              
              2008Property,
      plant and equipment
              
              $
              204,083
              
              
              $
              199,306Other,
      net
              
              
              (863
              )
              
              
              (3,846
              )Total
      deferred tax liability
              
              
              203,220
              
              
              
              195,460Less
      current deferred tax asset (liability)
              
              
              1,153
              
              
              
              (589
              )Total
      long-term deferred tax liability
              
              $
              204,373
              
              
              $
              194,871
 
 10.
              MAJOR CUSTOMERS AND
      SUPPLIERS:
 
 Our major
customers are in the natural gas operations segments.  Our natural gas
operations have a concentration of customers in natural gas transmission,
distribution and marketing, as well as industrial end-users while our NGL
operations have a concentration of customers in the refining and petrochemical
industries.  These concentrations of customers may impact our overall
exposure to credit risk, either positively or negatively.  Management
believes that our portfolio of accounts receivable is sufficiently diversified
to minimize any potential credit risk.  No single customer accounted
for 10% or more of our consolidated revenue.
 
 We had
gross segment purchases as a percentage of total purchases from major suppliers
as follows:
 
 Years
      Ended December 31,
              
              
              Four
      Months Ended December 31,
              
              
              Year
      Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Propane
      segmentsUnaffiliated:M.P.
      Oils, Ltd.
              
              
              15.1
              %
              
              
              14.9
              %
              
              
              14.2
              %
              
              
              20.7
              %Targa
      Liquids
              
              
              14.3
              %
              
              
              15.0
              %
              
              
              15.9
              %
              
              
              22.6
              %Affiliated:Enterprise
              
              
              50.3
              %
              
              
              50.7
              %
              
              
              50.6
              %
              
              
              22.1
              %
 
 Enterprise
GP Holdings, L.P. and its subsidiaries (“Enterprise” or “EPE”) became related
parties on May 7, 2007, as discussed in Note 14.  Titan purchases the
majority of its propane from Enterprise pursuant to an agreement that expires in
March 2010 and contains renewal and extension options.
 
 We sold
our investment in M-P Energy in October 2007.  In connection with the
sale, we executed a propane purchase agreement for approximately 90.0 million
gallons per year through 2015 at market prices plus a nominal fee.
 
 This
concentration of suppliers may impact our overall operations either positively
or negatively.  However, management believes that the diversification
of suppliers is sufficient to enable us to purchase all of our supply needs at
market prices without a material disruption of operations if supplies are
interrupted from any of our existing sources.  Although no assurances
can be given that supplies of natural gas, propane and NGLs will be readily
available in the future, we expect a sufficient supply to continue to be
available.
 
 11.
              REGULATORY MATTERS,
      COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL
      LIABILITIES:
 
 Regulatory
Matters
 
 In August
2009, we filed an application for FERC authority to construct and operate the
Tiger pipeline.  Approval from the FERC is still pending.
 
 On
September 29, 2006, Transwestern filed revised tariff sheets under Section 4(e)
of the Natural Gas Act (“NGA”) proposing a general rate increase to be effective
on November 1, 2006.  In April 2007, the FERC approved a Stipulation
and Agreement of Settlement that resolved the primary components of the rate
case.  Transwestern’s tariff rates and fuel rates are now final for
the period of the settlement.  Transwestern is required to file a new
rate case no later than October 1, 2011.
  46
  The
Phoenix project, as filed with the FERC on September 15, 2006, includes the
construction and operation of approximately 260 miles of 36-inch or larger
diameter pipeline extending from Transwestern’s existing mainline in Yavapai
County, Arizona to delivery points in the Phoenix, Arizona area and certain
looping on Transwestern’s existing San Juan Lateral with approximately 25 miles
of 36-inch diameter pipeline.  On November 15, 2007, the FERC issued
an order granting Transwestern its Certificate of Public Convenience and
Necessity (“Order”).  Pursuant to the Order, Transwestern filed its
initial Implementation Plan on November 14, 2007 and accepted the Order on
November 19, 2007.  The San Juan Lateral portion of the project was
placed in service effective July 2008 and the pipeline to the Phoenix area was
placed in service effective March 2009.
 
 Guarantees
 
 MEP
Guarantee
 
 ETP has
guaranteed 50% of the obligations of MEP under its senior revolving credit
facility (the “MEP Facility”), with the remaining 50% of MEP Facility
obligations guaranteed by KMP.  Subject to certain exceptions, ETP’s
guarantee may be proportionately increased or decreased if its ownership
percentage increases or decreases.  The MEP Facility is unsecured and
matures on February 28, 2011.  Amounts borrowed under the MEP Facility
bear interest at a rate based on either a Eurodollar rate or a prime
rate.  The commitment fee payable on the unused portion of the MEP
Facility varies based on both our credit rating and that of KMP, with a maximum
fee of 0.15%.  The MEP Facility contains covenants that limit (subject
to certain exceptions) MEP’s ability to grant liens, incur indebtedness, engage
in transactions with affiliates, enter into restrictive agreements, enter into
mergers, or dispose of substantially all of its assets.
 
 The
commitment amount under the MEP Facility was originally $1.4
billion.  In September 2009, MEP issued senior notes totaling $800.0
million, the proceeds of which were used to repay borrowings under the MEP
Facility.  The senior notes issued by MEP are not guaranteed by ETP or
KMP.  In October 2009, the members made additional capital
contributions to MEP, which MEP used to further reduce the outstanding
borrowings under the MEP Facility.  Subsequent to this repayment, the
commitment amount under the MEP Facility was reduced from $1.4 billion to $275.0
million.
 
 As of
December 31, 2009, MEP had $29.5 million of outstanding borrowings and $33.3
million of letters of credit issued under the MEP Facility.  ETP’s
contingent obligations with respect to its 50% guarantee of MEP’s outstanding
borrowings and letters of credit were $14.7 million and $16.6 million,
respectively, as of December 31, 2009.  The weighted average interest
rate on the total amount outstanding as of December 31, 2009 was
3.3%.
 
 FEP
Guarantee
 
 On
November 13, 2009, FEP entered into a credit agreement that provides for a $1.1
billion senior revolving credit facility (the “FEP Facility”).  ETP
has guaranteed 50% of the obligations of FEP under the FEP Facility, with the
remaining 50% of FEP Facility obligations guaranteed by KMP.  Subject
to certain exceptions, ETP’s guarantee may be proportionately increased or
decreased if ETP’s ownership percentage increases or decreases.  The
FEP Facility is available through May 11, 2012.  Amounts borrowed
under the FEP Facility bear interest at a rate based on either a Eurodollar rate
or prime rate.  The commitment fee payable on the unused portion of
the FEP Facility varies based on both our credit rating and that of KMP, with a
maximum fee of 1.0%.
 
 As of
December 31, 2009, FEP had $355.0 million of outstanding borrowings issued under
the FEP Facility.  ETP’s contingent obligation with respect to its 50%
guarantee of FEP’s outstanding borrowings was $177.5 million as of December 31,
2009.  The weighted average interest rate on the total amount
outstanding as of December 31, 2009 was 3.2%.
 
 Commitments
 
 In the
normal course of our business, we purchase, process and sell natural gas
pursuant to long-term contracts and enter into long-term transportation and
storage agreements.  Such contracts contain terms that are customary
in the industry.  We have also entered into several propane purchase
and supply commitments, which are typically one year agreements with varying
terms as to quantities, prices and expiration dates.
  47
  We have
certain non-cancelable leases for property and equipment, which require fixed
monthly rental payments and expire at various dates through
2034.  Rental expense under these operating leases has been included
in operating expenses in the accompanying statements of operations and totaled
approximately $19.8 million, $17.2 million, $9.4 million and $33.2 million for
the years ended December 31, 2009 and 2008, the four months ended December 31,
2007 and the fiscal year ended August 31, 2007, respectively.
 
 Future
minimum lease commitments for such leases are:
 
 2010
              
              $
              27,2162011
              
              
              24,7862012
              
              
              22,5222013
              
              
              20,3852014
              
              
              17,907Thereafter
              
              
              214,088
 
 We have
forward commodity contracts, which are expected to be settled by physical
delivery.  Short-term contracts, which expire in less than one year
require delivery of up to 390,564 MMBtu/d.  Long-term contracts
require delivery of up to 125,551 MMBtu/d and extend through May
2014.
 
 During
fiscal year 2007, we entered into a long-term agreement with CenterPoint Energy
Resources Corp (“CenterPoint”) to provide the natural gas utility with firm
transportation and storage services on our HPL System located along the Texas
gulf coast region.  Under the terms of the agreements, CenterPoint has
contracted for 129 Bcf per year of firm transportation capacity combined with 10
Bcf of working gas storage capacity in our Bammel storage facility.
 
 We have a
transportation agreement with TXU Portfolio Management Company, LP (“TXU
Shipper”) to transport a minimum of 100,000 MMBtu per year through
2012.  We also have two natural gas storage agreements with TXU
Shipper to store gas at two natural gas facilities that are part of the ET Fuel
System that expire in 2012.  As of December 31, 2009 and 2008 and
August 31, 2007, respectively, the Partnership was entitled to receive
additional fees for the difference between actual volumes transported by TXU
Shipper on the ET Fuel System and the minimum amount as stated above during the
twelve-month periods ended each May 31st.  As a result, the
Partnership recognized approximately $11.7 million, $10.7 million and $10.8
million in additional fees during the second quarter of 2008 and the third
fiscal quarter of 2007, respectively.
 
 We have
signed long-term agreements with several parties committing firm transportation
volumes into the East Texas pipeline.  Those commitments include an
agreement with XTO Energy Inc. (“XTO”) to deliver approximately 200,000 MMBtu/d
of natural gas into the pipeline that expires in June 2012.  Exxon
Mobil Corporation (“ExxonMobil”) and XTO announced an agreement whereby
ExxonMobil will acquire XTO.  The pending acquisition, expected to be
completed in the second quarter of 2010, is not expected to result in any
changes to these commitments.
 
 We also
have two long-term agreements committing firm transportation volumes on certain
of our transportation pipelines.  The two contracts require an
aggregated capacity of approximately 238,000 MMBtu/d of natural gas and extend
through 2011.
 
 Titan has
a purchase contract with Enterprise (see Note 14) to purchase the majority of
Titan’s propane requirements.  The contract continues until March 2010
and contains renewal and extension options.  The contract contains
various service level agreements between the parties.
 
 In
connection with the sale of ETP’s investment in M-P Energy in October 2007, ETP
executed a propane purchase agreement for approximately 90.0 million gallons per
year through 2015 at market prices plus a nominal fee.
  48
  We have
commitments to make capital contributions to our joint ventures, for which we
expect to make capital contributions of between $90 million and $105 million
during 2010.
 
 Litigation
and Contingencies
 
 We may,
from time to time, be involved in litigation and claims arising out of our
operations in the normal course of business.  Natural gas and propane
are flammable, combustible gases.  Serious personal injury and
significant property damage can arise in connection with their transportation,
storage or use.  In the ordinary course of business, we are sometimes
threatened with or named as a defendant in various lawsuits seeking actual and
punitive damages for product liability, personal injury and property
damage.  We maintain liability insurance with insurers in amounts and
with coverages and deductibles management believes are reasonable and prudent,
and which are generally accepted in the industry.  However, there can
be no assurance that the levels of insurance protection currently in effect will
continue to be available at reasonable prices or that such levels will remain
adequate to protect us from material expenses related to product liability,
personal injury or property damage in the future.
 
 FERC/CFTC and Related
Matters.  On July 26, 2007, the FERC issued to ETP an Order to
Show Cause and Notice of Proposed Penalties (the “Order and Notice”) that
contains allegations that ETP violated FERC rules and
regulations.  The FERC alleged that ETP engaged in manipulative or
improper trading activities in the Houston Ship Channel, primarily on two dates
during the fall of 2005 following the occurrence of Hurricanes Katrina and Rita,
as well as on eight other occasions from December 2003 through August 2005, in
order to benefit financially from ETP’s commodities derivatives positions and
from certain of ETP’s index-priced physical gas purchases in the Houston Ship
Channel.  The FERC alleged that during these periods ETP violated the
FERC’s then-effective Market Behavior Rule 2, an anti-market manipulation rule
promulgated by the FERC under authority of the Natural Gas Act
(“NGA”).  The FERC alleges that ETP violated this rule by artificially
suppressing prices that were included in the Platts Inside FERC Houston Ship
Channel index, published by McGraw-Hill Companies, on which the pricing of many
physical natural gas contracts and financial derivatives are
based.  In its Order and Notice, the FERC also alleged that ETP
manipulated daily prices at the Waha and Permian Hubs in west Texas on two
dates.  The FERC also alleged that one of our intrastate pipelines
violated various FERC regulations by, among other things, granting undue
preferences in favor of an affiliate.  In its Order and Notice, the
FERC specified that it was seeking $69.9 million in disgorgement of profits,
plus interest, and $82.0 million in civil penalties relating to these market
manipulation claims.  The FERC specified that it was also seeking to
revoke, for a period of 12 months, ETP’s blanket marketing authority for sales
of natural gas in interstate commerce at market-based prices.  In
February 2008, the FERC’s Enforcement Staff also recommended that the FERC
pursue market manipulation claims related to ETP’s trading activities in October
2005 for November 2005 monthly deliveries, a period not previously covered by
the FERC’s allegations in the Order and Notice, and that ETP be assessed an
additional civil penalty of $25.0 million and be required to disgorge
approximately $7.3 million of alleged unjust profits related to this additional
month.
 
 On August
26, 2009, ETP entered into a settlement agreement with the FERC’s Enforcement
Staff with respect to the pending FERC claims against ETP and, on September 21,
2009, the FERC approved the settlement agreement without
modification.  The agreement settles all outstanding FERC claims
against ETP and provides that ETP make a $5.0 million payment to the federal
government and establish a $25.0 million fund for the purpose of settling
related third-party claims against ETP, including existing litigation claims as
well as any new claims that may be asserted against this
fund.  Administrative law judge appointed by the FERC will determine
the validity of any third party claim against this fund.  Any party
who receives money from this fund will be required to waive all claims against
ETP related to this matter.  Pursuant to the settlement agreement, the
FERC made no findings of fact or conclusions of law.  In addition, the
settlement agreement specifies that by exceeding the settlement agreement, ETP
does not admit or concede to the FERC or any third party any actual or potential
fault, wrongdoing or liability in connection with ETP’s alleged conduct related
to the FERC claims.  The settlement agreement also requires ETP to
maintain specified compliance programs and to conduct independent annual audits
of such programs for a two-year period.
 
 We made
the $5.0 million payment and established the $25.0 million fund in October
2009.  The allocation of the $25.0 million fund is expected to be
determined in 2010.
 
 In
addition to the FERC legal action, third parties have asserted claims and may
assert additional claims against us and ETP alleging damages related to these
matters.  In this regard, several natural gas producers and a natural
gas marketing company have initiated legal proceedings in Texas state courts
against us and ETP for claims related to the FERC claims.  These suits
contain contract and tort claims relating to alleged manipulation of natural gas
prices at the Houston Ship Channel and the Waha Hub in West Texas, as well as
the natural gas price indices related to these markets and the Permian Basin
natural gas price index during the period from December 2003 through December
2006, and seek unspecified direct, indirect, consequential and exemplary
damages.  One of the suits against us and ETP contains an additional
allegation that we and ETP transported gas in a manner that favored our
affiliates and discriminated against the plaintiff, and otherwise artificially
affected the market price of gas to other parties in the market.  We
have moved to compel arbitration and/or contested subject-matter jurisdiction in
some of these cases.  In one of these cases, the Texas Supreme Court
ruled on July 3, 2009 that the state district court erred in ruling that a
plaintiff was entitled to pre-arbitration discovery and therefore remanded to
the state district court with a direction to rule on our original motion to
compel arbitration pursuant to the terms of the arbitration clause in a natural
gas contract between us and the plaintiff.  This plaintiff has filed a
motion with the Texas Supreme Court requesting a rehearing of the
ruling.
  49
  ETP has
also been served with a complaint from an owner of royalty interests in natural
gas producing properties, individually and on behalf of a putative class of
similarly situated royalty owners, working interest owners and
producer/operators, seeking arbitration to recover damages based on alleged
manipulation of natural gas prices at the Houston Ship Channel.  ETP
filed an original action in Harris County state court seeking a stay of the
arbitration on the ground that the action is not arbitrable, and the state court
granted our motion for summary judgment on that issue.  This action is
currently on appeal before the First Court of Appeals, Houston,
Texas.
 
 A
consolidated class action complaint has been filed against ETP in the United
States District Court for the Southern District of Texas.  This action
alleges that ETP engaged in intentional and unlawful manipulation of the price
of natural gas futures and options contracts on the NYMEX in violation of the
Commodity Exchange Act (“CEA”).  It is further alleged that during the
class period December 29, 2003 to December 31, 2005, ETP had the market power to
manipulate index prices, and that ETP used this market power to artificially
depress the index prices at major natural gas trading hubs, including the
Houston Ship Channel, in order to benefit ETP’s natural gas physical and
financial trading positions, and that ETP intentionally submitted price and
volume trade information to trade publications.  This complaint also
alleges that ETP violated the CEA by knowingly aiding and abetting violations of
the CEA.  The plaintiffs state that this allegedly unlawful depression
of index prices by ETP manipulated the NYMEX prices for natural gas futures and
options contracts to artificial levels during the class period, causing
unspecified damages to the plaintiffs and all other members of the putative
class who sold natural gas futures or who purchased and/or sold natural gas
options contracts on NYMEX during the class period.  The plaintiffs
have requested certification of their suit as a class action and seek
unspecified damages, court costs and other appropriate relief.  On
January 14, 2008, ETP filed a motion to dismiss this suit on the grounds of
failure to allege facts sufficient to state a claim.  On March 20,
2008, the plaintiffs filed a second consolidated class action
complaint.  In response to this new pleading, on May 5, 2008, ETP
filed a motion to dismiss the complaint.  On March 26, 2009, the court
issued an order dismissing the complaint, with prejudice, for failure to state a
claim.  On April 9, 2009, the plaintiffs moved for reconsideration of
the order dismissing the complaint, and on August 26, 2009, the court denied the
plaintiffs’ motion for reconsideration.  On September 28, 2009, these
decisions were appealed by the plaintiffs to the United States Court of Appeals
for the 5th Circuit.
 
 On March
17, 2008, a second class action complaint was filed against ETP in the United
States District Court for the Southern District of Texas.  This action
alleges that ETP engaged in unlawful restraint of trade and intentional
monopolization and attempted monopolization of the market for fixed-price
natural gas baseload transactions at the Houston Ship Channel from December 2003
through December 2005 in violation of federal antitrust law.  The
complaint further alleges that during this period ETP exerted monopoly power to
suppress the price for these transactions to non-competitive levels in order to
benefit ETP’s own physical natural gas positions.  The plaintiff has,
individually and on behalf of all other similarly situated sellers of physical
natural gas, requested certification of its suit as a class action and seeks
unspecified treble damages, court costs and other appropriate
relief.  On May 19, 2008, ETP filed a motion to dismiss this
complaint.  On March 26, 2009, the court issued an order dismissing
the complaint.  The court found that the plaintiffs failed to state a
claim on all causes of action and for anti-trust injury, but granted leave to
amend.  On April 23, 2009, the plaintiffs filed a motion for leave to
amend to assert a claim for common law fraud and attached a proposed amended
complaint as an exhibit.  ETP opposed the motion and cross-moved to
dismiss.  On August 7, 2009, the court denied the plaintiff’s motion
and granted ETP’s motion to dismiss the complaint.  On September 10,
2009, this decision was appealed by the plaintiff to the United States Court of
Appeals for the 5th Circuit.
  50
  ETP is
expensing the legal fees, consultants’ fees and other expenses relating to these
matters in the periods in which such costs are incurred.  ETP records
accruals for litigation and other contingencies whenever required by applicable
accounting standards.  Based on the terms of the settlement agreement
with the FERC described above, we made the $5.0 million payment and established
the $25.0 million fund in October 2009.  While ETP expects the
after-tax cash impact of the settlement to be less than $30.0 million due to tax
benefits resulting from the portion of the payment that is used to satisfy third
party claims, ETP may not be able to realize such tax
benefits.  Although this payment covers the $25.0 million required by
the settlement agreement to be applied to resolve third party claims, including
the existing third party litigation described above, it is possible that the
amount ETP becomes obliged to pay to resolve third party litigation related to
these matters, whether on a negotiated settlement basis or otherwise, will
exceed the amount of the payment related to these matters.  In
accordance with applicable accounting standards, ETP will review the amount of
their accrual related to these matters as developments related to these matters
occur and ETP will adjust their accrual if ETP determines that it is probable
that the amount ETP may ultimately become obliged to pay as a result of the
final resolution of these matters is greater than the amount of ETP’s accrual
for these matters.  As ETP’s accrual amounts are non-cash, any cash
payment of an amount in resolution of these matters would likely be made from
cash from operations or borrowings, which payments would reduce ETP’s cash
available to service ETP’s indebtedness either directly or as a result of
increased principal and interest payments necessary to service any borrowings
incurred to finance such payments.  If these payments are substantial,
ETP may experience a material adverse impact on its results of operations and
its liquidity.
 
 In re
Natural Gas Royalties Qui Tam Litigation.  MDL Docket No. 1293 (D.
WY), Jack Grynberg, an individual, has filed actions against a number of
companies, including Transwestern, now transferred to the U.S. District Court
for the District of Wyoming, for damages for mis-measurement of gas volumes and
Btu content, resulting in lower royalties to mineral interest
owners.  On October 20, 2006, the District Judge adopted in part the
earlier recommendation of the Special Master in the case and ordered the
dismissal of the case against Transwestern.  Transwestern believes
that its measurement practices conformed to the terms of its FERC Gas Tariff,
which were filed with and approved by the FERC.  As a result,
Transwestern believes that is has meritorious defenses to these lawsuits
(including FERC-related affirmative defenses, such as the filed rate/tariff
doctrine, the primary/exclusive jurisdiction of the FERC, and the defense that
Transwestern complied with the terms of its tariffs) and will continue to
vigorously defend against them, including any appeal which may be taken from the
dismissal of the Grynberg case.  A hearing was held on April 24, 2007
regarding Transwestern’s Supplemental Brief for Attorneys’ fees, which was filed
on January 8, 2007, and the issues are submitted and are awaiting a
decision.  Grynberg moved to have the cases he appealed remanded to
the district court for consideration in light of a recently-issued Supreme Court
case.  The defendants/appellees opposed the motion.  The
Tenth Circuit motions panel referred the remand motion to the merits panel to be
carried with the appeals.  Grynberg’s opening brief was filed on or
about July 31, 2007.  Appellee’s opposition brief was filed on or
about November 21, 2007.  Appellee Transwestern filed its separate
response brief on January 11, 2008 and Grynberg’s reply brief was filed in June
2008 and the hearing on all briefs was held in September 2008.  On
March 17, 2009, the Tenth Circuit affirmed the District Court’s
dismissal.  Appellant sought appellate rehearing on the matter and the
petition for rehearing was denied on May 4, 2009.  A petition for writ
of certiorari was filed by the Appellant on August 3, 2009, and the Supreme
Court denied the petition for writ of certiorari on October 5,
2009.  We do not believe the outcome of this case will have a material
adverse effect on our financial position, results of operations or cash
flows.
 
 Houston
Pipeline Cushion Gas Litigation.  At the time of the HPL System
acquisition, AEP Energy Services Gas Holding Company II, L.L.C., HPL
Consolidation LP and its subsidiaries (the “HPL Entities”), their parent
companies and American Electric Power Corporation (“AEP”), were engaged in
ongoing litigation with Bank of America (“B of A”) that related to AEP’s
acquisition of HPL in the Enron bankruptcy and B of A’s financing of cushion gas
stored in the Bammel storage facility (“Cushion Gas”).  This
litigation is referred to as the (“Cushion Gas Litigation”).  Under
the terms of the Purchase and Sale Agreement and the related Cushion Gas
Litigation Agreement, AEP and its subsidiaries that were the sellers of the HPL
Entities retained control of the Cushion Gas Litigation and have agreed to
indemnify ETC OLP and the HPL Entities for any damages arising from the Cushion
Gas Litigation and the loss of use of the Cushion Gas, up to a maximum of the
amount paid by ETC OLP for the HPL Entities and the working gas inventory
(approximately $1.00 billion in the aggregate).  The Cushion Gas
Litigation Agreement terminates upon final resolution of the Cushion Gas
Litigation.  In addition, under the terms of the Purchase and Sale
Agreement, AEP retained control of additional matters relating to ongoing
litigation and environmental remediation and agreed to bear the costs of or
indemnify ETC OLP and the HPL Entities for the costs related to such
matters.  On December 18, 2007, the United States District Court for
the Southern District of New York held that B of A is entitled to receive
monetary damages from AEP and the HPL Entities of approximately $347.3 million
less the monetary amount B of A would have incurred to remove 55 Bcf of natural
gas from the Bammel storage facility.  AEP is appealing the court
decision.  Based on the indemnification provisions of the Cushion Gas
Litigation Agreement, ETP does not expect that it will be liable for any portion
of this court award.
  51
  Other
Matters.  In addition to those matters described above, we or
our subsidiaries are a party to various legal proceedings and/or regulatory
proceedings incidental to our businesses.  For each of these matters,
we evaluate the merits of the case, our exposure to the matter, possible legal
or settlement strategies, the likelihood of an unfavorable outcome and the
availability of insurance coverage.  If we determine that an
unfavorable outcome of a particular matter is probable, can be estimated and is
not covered by insurance, we make an accrual for the matter.  For
matters that are covered by insurance, we accrue the related
deductible.  As of December 31, 2009 and 2008, accruals of
approximately $11.1 million and $8.5 million, respectively, were recorded
related to deductibles.  As new information becomes available, our
estimates may change.  The impact of these changes may have a
significant effect on our results of operations in a single period.
 
 The
outcome of these matters cannot be predicted with certainty and it is possible
that the outcome of a particular matter will result in the payment of an amount
in excess of the amount accrued for the matter.  As our accrual
amounts are non-cash, any cash payment of an amount in resolution of a
particular matter would likely be made from cash from operations or
borrowings.  If cash payments to resolve a particular matter
substantially exceed our accrual for such matter, we may experience a material
adverse impact on our results of operations, cash available for distribution and
our liquidity.
 
 As of
December 31, 2008, an accrual of $21.0 million was recorded as accrued and other
current liabilities and other non-current liabilities on our consolidated
balance sheets for our contingencies and current litigation matters, excluding
accruals related to environmental matters, and we did not have any such accruals
as of December 31, 2009.
 
 Environmental
Matters
 
 Our
operations are subject to extensive federal, state and local environmental laws
and regulations that require expenditures for remediation at operating
facilities and waste disposal sites.  Although we believe our
operations are in substantial compliance with applicable environmental laws and
regulations, risks of additional costs and liabilities are inherent in the
natural gas pipeline and processing business, and there can be no assurance that
significant costs and liabilities will not be incurred.  Moreover, it
is possible that other developments, such as increasingly stringent
environmental laws, regulations and enforcement policies thereunder, and claims
for damages to property or persons resulting from the operations, could result
in substantial costs and liabilities.  Accordingly, we have adopted
policies, practices and procedures in the areas of pollution control, product
safety, occupational health, and the handling, storage, use, and disposal of
hazardous materials to prevent material environmental or other damage, and to
limit the financial liability, which could result from such
events.  However, some risk of environmental or other damage is
inherent in the natural gas pipeline and processing business, as it is with
other entities engaged in similar businesses.
 
 Transwestern
conducts soil and groundwater remediation at a number of its
facilities.  Some of the clean up activities include remediation of
several compressor sites on the Transwestern system for contamination by
polychlorinated biphenyls (“PCBs”) and the costs of this work are not eligible
for recovery in rates.  The total accrued future estimated cost of
remediation activities expected to continue through 2018 is $8.6
million.  Transwestern received FERC approval for rate recovery of
projected soil and groundwater remediation costs not related to PCBs effective
April 1, 2007.
 
 Transwestern,
as part of ongoing arrangements with customers, continues to incur costs
associated with containing and removing potential PCBs.  Future costs
cannot be reasonably estimated because remediation activities are undertaken as
potential claims are made by customers and former customers.  However,
such future costs are not expected to have a material impact on our financial
position, results of operations or cash flows.
 
 Environmental
regulations were recently modified for the EPA’s Spill Prevention, Control and
Countermeasures (“SPCC”) program.  We are currently reviewing the
impact to our operations and expect to expend resources on tank integrity
testing and any associated corrective actions as well as potential upgrades to
containment structures.  Costs associated with tank integrity testing
and resulting corrective actions cannot be reasonably estimated at this time,
but we believe such costs will not have a material adverse effect on our
financial position, results of operations or cash flows.
  52
  In July
2001, HOLP acquired a company that had previously received a request for
information from the U.S. Environmental Protection Agency (the “EPA”) regarding
potential contribution to a widespread groundwater contamination problem in San
Bernardino, California, known as the Newmark Groundwater
Contamination.  Although the EPA has indicated that the groundwater
contamination may be attributable to releases of solvents from a former military
base located within the subject area that occurred long before the facility
acquired by HOLP was constructed, it is possible that the EPA may seek to
recover all or a portion of groundwater remediation costs from private parties
under the Comprehensive Environmental Response, Compensation, and Liability Act
(commonly called Superfund).  We have not received any follow-up
correspondence from the EPA on the matter since our acquisition of the
predecessor company in 2001.  Based upon information currently
available to HOLP, it is believed that HOLP’s liability if such action were to
be taken by the EPA would not have a material adverse effect on our financial
condition or results of operations.
 
 Petroleum-based
contamination or environmental wastes are known to be located on or adjacent to
six sites on which HOLP presently has, or formerly had, retail propane
operations.  These sites were evaluated at the time of their
acquisition.  In all cases, remediation operations have been or will
be undertaken by others, and in all six cases, HOLP obtained indemnification
rights for expenses associated with any remediation from the former owners or
related entities.  We have not been named as a potentially responsible
party at any of these sites, nor have our operations contributed to the
environmental issues at these sites.  Accordingly, no amounts have
been recorded in our December 31, 2009 or our December 31, 2008 consolidated
balance sheets.  Based on information currently available to us, such
projects are not expected to have a material adverse effect on our financial
condition or results of operations.
 
 Environmental
exposures and liabilities are difficult to assess and estimate due to unknown
factors such as the magnitude of possible contamination, the timing and extent
of remediation, the determination of our liability in proportion to other
parties, improvements in cleanup technologies and the extent to which
environmental laws and regulations may change in the future.  Although
environmental costs may have a significant impact on the results of operations
for any single period, we believe that such costs will not have a material
adverse effect on our financial position.
 
 As of
December 31, 2009 and 2008, accruals on an undiscounted basis of $12.6 million
and $13.3 million, respectively, were recorded in our consolidated balance
sheets as accrued and other current liabilities and other non-current
liabilities to cover material environmental liabilities related to certain
matters assumed in connection with the HPL acquisition, the Transwestern
acquisition, and the potential environmental liabilities for three sites that
were formerly owned by Titan or its predecessors.
 
 Based on
information available at this time and reviews undertaken to identify potential
exposure, we believe the amount reserved for all of the above environmental
matters is adequate to cover the potential exposure for clean-up
costs.
 
 ETP’s
pipeline operations are subject to regulation by the U.S. Department of
Transportation (“DOT”) under the Pipeline Hazardous Materials Safety
Administration (“PHMSA”), pursuant to which the PHMSA has established
requirements relating to the design, installation, testing, construction,
operation, replacement and management of pipeline
facilities.  Moreover, the PHMSA, through the Office of Pipeline
Safety, has promulgated a rule requiring pipeline operators to develop integrity
management programs to comprehensively evaluate their pipelines, and take
measures to protect pipeline segments located in what the rule refers to as
(“high consequence areas”).  Activities under these integrity
management programs involve the performance of internal pipeline inspections,
pressure testing, or other effective means to assess the integrity of these
regulated pipeline segments, and the regulations require prompt action to
address integrity issues raised by the assessment and analysis.  For
the years ended December 31, 2009 and 2008, $31.4 million and $23.3 million,
respectively, of capital costs and $18.5 million and $13.1 million,
respectively, of operating and maintenance costs have been incurred for pipeline
integrity testing.  Integrity testing and assessment of all of these
assets will continue, and the potential exists that results of such testing and
assessment could cause ETP to incur even greater capital and operating
expenditures for repairs or upgrades deemed necessary to ensure the continued
safe and reliable operation of its pipelines.
  53
  12.
              PRICE RISK MANAGEMENT
      ASSETS AND LIABILITIES:
 
 See Note
2 for further discussion of our accounting for derivative instruments and
hedging activities.
 
 Commodity
Price Risk
 
 The
following table details the outstanding commodity-related
derivatives:
 
 December 31, 2009
              
              
              December 31, 2008Commodity
              
              Notional
      Volume MMBtu
              
              
              Maturity
              
              
              Notional
      Volume MMBtu
              
              
              MaturityMark
      to Market DerivativesBasis
      Swaps IFERC/NYMEX
              Gas
              
              
              72,325,000
              
              
              
              2010-2011
              
              
              
              15,720,000
              
              
              
              2009-2011Swing
      Swaps IFERC
              Gas
              
              
              (38,935,000
              )
              
              
              2010
              
              
              
              (58,045,000
              )
              
              
              2009Fixed
      Swaps/Futures
              Gas
              
              
              4,852,500
              
              
              
              2010-2011
              
              
              
              (20,880,000
              )
              
              
              2009-2010Options
      - Puts
              Gas
              
              
              2,640,000
              
              
              
              2010
              
              
              
              -
              
              
              
              N/AOptions
      - Calls
              Gas
              
              
              (2,640,000
              )
              
              
              2010
              
              
              
              -
              
              
              
              N/AForwards/Swaps
      - in Gallons
              Propane
              
              
              6,090,000
              
              
              
              2010
              
              
              
              47,313,002
              
              
              
              2009Fair
      Value Hedging DerivativesBasis
      Swaps IFERC/NYMEX
              Gas
              
              
              (22,625,000
              )
              
              
              2010
              
              
              
              -
              
              
              
              N/AFixed
      Swaps/Futures
              Gas
              
              
              (27,300,000
              )
              
              
              2010
              
              
              
              -
              
              
              
              N/AHedged
      Item - Inventory
              Gas
              
              
              27,300,000
              
              
              
              2010
              
              
              
              -
              
              
              
              N/ACash
      Flow Hedging DerivativesBasis
      Swaps IFERC/NYMEX
              Gas
              
              
              (13,225,000
              )
              
              
              2010
              
              
              
              (9,085,000
              )
              
              
              2009Fixed
      Swaps/Futures
              Gas
              
              
              (22,800,000
              )
              
              
              2010
              
              
              
              (9,085,000
              )
              
              
              2009Forwards/Swaps
      - in Gallons
              Propane/Ethane
              
              
              20,538,000
              
              
              
              2010
              
              
              
              -
              
              
              
              N/A
 
 We expect
gains of $2.0 million related to commodity derivatives to be reclassified into
earnings over the next year related to amounts currently reported in
AOCI.  The amount ultimately realized, however, will differ as
commodity prices change and the underlying physical transaction
occurs.
 
 As of
July 2008, we no longer engage in the trading of commodity derivative
instruments that are not substantially offset by physical or other commodity
derivative positions.  As a result, we no longer have any material
exposure to market risk from such activities.  The derivative
contracts that were previously entered into for trading purposes were recognized
in the consolidated balance sheets at fair value, and changes in the fair value
of these derivative instruments are recognized in revenue in the consolidated
statements of operations on a net basis.  Trading activities,
including trading of physical gas and financial derivative instruments, resulted
in net losses of approximately $26.2 million for the year ended December 31,
2008, net losses of approximately $2.3 million for the four-month transition
period ended December 31, 2007 and net gains of approximately $2.2 million for
the fiscal year ended August 31, 2007.  There were no gains or losses
associated with trading activities during the year ended December 31,
2009.
 
 Interest
Rate Risk
 
 We are
exposed to market risk for changes in interest rates.  We manage a
portion of our current and future interest rate exposures by utilizing interest
rate swaps.  We have the following interest rate swaps outstanding as
of December 31, 2009:
 
 ·
              Interest
      rate swaps with a notional amount of $300.0 million to pay an average
      fixed rate of 5.20% and receive a floating rate based on
      LIBOR.  These swaps settle in May
  2016;
 
 ·
              Interest
      rate swaps with a notional amount of $500.0 million to pay a fixed rate of
      4.57% and receive a floating rate based on LIBOR.  These swaps
      settle in November 2012 with a cancellable option in November 2010;
      and,
  54
  ·
              Interest
      rate swaps with a notional amount of $700.0 million to pay an average
      fixed rate of 4.84% and receive a floating rate based on
      LIBOR.  These swaps settle in November
  2012.
 
 In
January 2010, we entered into interest rate swaps with notional amounts of
$350.0 million and $750.0 million to pay a floating rate based on LIBOR and
receive a fixed rate that mature in July 2013 and February 2015,
respectively.  These swaps hedge against changes in the fair value of
our fixed rate debt.
 
 Derivative
Summary
 
 The
following table provides a balance sheet overview of the Partnership’s
derivative assets and liabilities as of December 31, 2009 and December 31,
2008:
 
 Fair Value of Derivative
      InstrumentsAsset Derivatives
              
              
              Liability DerivativesBalance Sheet Location
              
              December 31,
                2009
              
              
              December 31,
                2008
              
              
              December 31,
                2009
              
              
              December 31,
                2008Derivatives
      designated as hedging instruments:Commodity
      Derivatives (margin deposits)
              Deposits
      Paid to Vendors
              
              $
              669
              
              
              $
              10,665
              
              
              $
              (24,035
              )
              
              $
              (1,504
              )Commodity
      Derivatives
              Price
      Risk Management Assets/Liabilities
              
              
              8,443
              
              
              
              918
              
              
              
              (201
              )
              
              
              (119
              )Interest
      Rate Swap Derivatives
              Price
      Risk Management Assets/Liabilities
              
              
              -
              
              
              
              -
              
              
              
              (61,879
              )
              
              
              (71,042
              )Total
      derivatives designated as hedging instruments
              
              $
              9,112
              
              
              $
              11,583
              
              
              $
              (86,115
              )
              
              $
              (72,665
              )Derivatives
      not designated as hedging instruments:Commodity
      Derivatives (margin deposits)
              Deposits
      Paid to Vendors
              
              $
              72,851
              
              
              $
              432,614
              
              
              $
              (36,950
              )
              
              $
              (335,685
              )Commodity
      Derivatives
              Price
      Risk Management Assets/Liabilities
              
              
              3,928
              
              
              
              17,244
              
              
              
              (241
              )
              
              
              (55,954
              )Interest
      Rate Swap Derivatives
              Price
      Risk Management Assets/Liabilities
              
              
              -
              
              
              
              -
              
              
              
              (76,157
              )
              
              
              (149,765
              )Total
      derivatives not designated as hedging instruments
              
              $
              76,779
              
              
              $
              449,858
              
              
              $
              (113,348
              )
              
              $
              (541,404
              )Total
      derivatives
              
              
              $
              85,891
              
              
              $
              461,441
              
              
              $
              (199,463
              )
              
              $
              (614,069
              )
 
 We
disclose the non-exchange traded financial derivative instruments as price risk
management assets and liabilities on our consolidated balance sheets at fair
value with amounts classified as either current or long-term depending on the
anticipated settlement date.
 
 We
utilize master-netting agreements and have maintenance margin deposits with
certain counterparties in the OTC market and with clearing
brokers.  Payments on margin deposits are required when the value of a
derivative exceeds our pre-established credit limit with the
counterparty.  Margin deposits are returned to us on the settlement
date for non-exchange traded derivatives.  We exchange margin calls on
a daily basis for exchange traded transactions.  Since the margin
calls are made daily with the exchange brokers, the fair value of the financial
derivative instruments are deemed current and netted in deposits paid to vendors
within other current assets in the consolidated balance sheets.  The
Partnership had net deposits with counterparties of $79.7 million and $78.2
million as of December 31, 2009 and December 31, 2008,
respectively.
 
 The
following tables detail the effect of the Partnership’s derivative assets and
liabilities in the consolidated statements of operations for the periods
presented:
 
 Location of Gain/(Loss) Reclassified from AOCI
      into Income (Effective and Ineffective Portion)
              
              Change in Value Recognized in OCI on
      Derivatives (Effective Portion)Years Ended
    December 31,
              
              
              Four Months Ended
      December 31,
              
              
              Year Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Derivatives
      in cash flow hedging relationships:Commodity
      Derivatives
              Cost
      of Products Sold
              
              $
              3,143
              
              
              $
              17,461
              
              
              $
              21,406
              
              
              $
              181,765Interest
      Rate Swap Derivatives
              Interest
      Expense
              
              
              (14,705
              )
              
              
              (57,676
              )
              
              
              (23,846
              )
              
              
              (578
              )Total
              
              
              $
              (11,562
              )
              
              $
              (40,215
              )
              
              $
              (2,440
              )
              
              $
              181,187
  55
  
 Location of Gain/(Loss) Reclassified from AOCI
      into Income (Effective and Ineffective Portion)
              
              Amount of Gain/(Loss) Reclassified from AOCI into
      Income (Effective Portion)Years Ended
    December 31,
              
              
              Four
      Months Ended December 31,
              
              
              Year
      Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Derivatives
      in cash flow hedging relationships:Commodity
      Derivatives
              Cost
      of Products Sold
              
              $
              9,924
              
              
              $
              42,874
              
              
              $
              8,673
              
              
              $
              162,340Interest
      Rate Swap Derivatives
              Interest
      Expense
              
              
              (26,882
              )
              
              
              (11,339
              )
              
              
              650
              
              
              
              3,879Total
              
              
              $
              (16,958
              )
              
              $
              31,535
              
              
              $
              9,323
              
              
              $
              166,219
 
 
 Location of Gain/(Loss) Reclassified from AOCI
      into Income (Effective and Ineffective Portion)
              
              Amount of Gain/(Loss) Recognized in Income on
      Ineffective Portion of DerivativesYears Ended
    December 31,
              
              
              Four
      Months Ended December 31,
              
              
              Year
      Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Derivatives
      in cash flow hedging relationships:Commodity
      Derivatives
              Cost
      of Products Sold
              
              $
              -
              
              
              $
              (8,347
              )
              
              $
              8,472
              
              
              $
              183Interest
      Rate Swap Derivatives
              Interest
      Expense
              
              
              -
              
              
              
              -
              
              
              
              (2
              )
              
              
              (1,813
              )Total
              
              
              $
              -
              
              
              $
              (8,347
              )
              
              $
              8,470
              
              
              $
              (1,630
              )
 
 
 Location of Gain/(Loss) Recognized in Income on
      Derivatives
              
              Amount of Gain/(Loss) Recognized in Income on
      Derivatives representing hedge ineffectiveness and amount excluded from
      the assessment of effectivenessYears Ended
    December 31,
              
              
              Four
      Months Ended December 31,
              
              
              Year
      Ended August 31,Derivatives
      in fair value hedging relationships:
              
              2009
              
              
              2008
              
              
              2007
              
              
              2007Commodity
      Derivatives(including
      hedged items)
              Cost
      of Products Sold
              
              $
              60,045
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -Total
              
              
              $
              60,045
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -
 
 
 Location of Gain/(Loss) Recognized in Income on
      Derivatives
                
                Amount of Gain/(Loss) Recognized in Income on
      DerivativesYears Ended
    December 31,
                
                
                Four
      Months Ended December 31,
                
                
                Year
      Ended August 31,Derivatives
      not designated as hedging instruments:
                
                2009
                
                
                2008
                
                
                2007
                
                
                2007Commodity
      Derivatives
                Cost
      of Products Sold
                
                $
                99,807
                
                
                $
                12,478
                
                
                $
                9,886
                
                
                $
                30,028Trading
      Commodity Derivatives
                Revenue
                
                
                -
                
                
                
                (28,283
                )
                
                
                (2,298
                )
                
                
                5,228Interest
      Rate Swap Derivatives
                Gains
      (Losses) on Non-hedged
                  Interest
      Rate Derivatives
                
                
                33,619
                
                
                
                (128,423
                )
                
                
                (28,683
                )
                
                
                29,081Total
                
                
                $
                133,426
                
                
                $
                (144,228
                )
                
                $
                (21,095
                )
                
                $
                64,337
 
 We
recognized an $18.6 million unrealized loss, a $35.5 million unrealized gain, a
$13.2 million unrealized gain and an $8.5 million unrealized loss on commodity
derivatives not in fair value hedging relationships (including the ineffective
portion of commodity derivatives in cash flow hedging relationships and amounts
classified as trading activity) for the years ended December 31, 2009 and 2008,
four months ended December 31, 2007 and the year August 31, 2007,
respectively.  In addition, for the year ended December 31, 2009, we
recognized unrealized gains of $48.6 million on commodity derivatives and
related hedged inventory accounted for as fair value hedges.  There
were no unrealized gains or losses on fair value hedging commodity derivatives
in the prior years since we commenced fair hedge accounting on our storage
inventory in April 2009.
  56
  Credit
Risk
 
 We
maintain credit policies with regard to our counterparties that we believe
minimize our overall credit risk.  These policies include an
evaluation of potential counterparties’ financial condition (including credit
ratings), collateral requirements under certain circumstances and the use of
standardized agreements, which allow for netting of positive and negative
exposure associated with a single counterparty.
 
 Our
counterparties consist primarily of financial institutions, major energy
companies and local distribution companies.  This concentration of
counterparties may impact its overall exposure to credit risk, either positively
or negatively in that the counterparties may be similarly affected by changes in
economic, regulatory or other conditions.  Based on our policies,
exposures, credit and other reserves, management does not anticipate a material
adverse effect on financial position or results of operations as a result of
counterparty performance.
 
 For
financial instruments, failure of a counterparty to perform on a contract could
result in our inability to realize amounts that have been recorded on our
consolidated balance sheet and recognized in net income or other comprehensive
income.
 
 13.
              RETIREMENTBENEFITS:
 
 ETP
sponsors a 401(k) savings plan, which covers virtually all
employees.  Employer matching contributions are calculated using a
formula based on employee contributions.  Prior to 2009,
employer-matching contributions were discretionary.  We made matching
contributions of $9.8 million, $9.7 million, $2.6 million and $8.5 million to
the 401(k) savings plan for the years ended December 31, 2009 and 2008, the four
months ended December 31, 2007, and the fiscal year ended August 31, 2007,
respectively.
 
 14.
              RELATED PARTY
      TRANSACTIONS:
 
 On May 7,
2007, Ray Davis, previously the Co-Chairman of ETE and Co-Chairman and Co-Chief
Executive Officer of ETP (retired August 15, 2007), and Natural Gas Partners VI,
L.P. (“NGP”) and affiliates of each, sold approximately 38,976,090 ETE Common
Units (17.6% of the outstanding Common Units of ETE) to
Enterprise.  In addition to the purchase of ETE Common Units,
Enterprise acquired a non-controlling equity interest in our General Partner, LE
GP, LLC (“LE GP”).  Cash consideration paid by Enterprise totaled
approximately $1.65 billion, reflecting a purchase price of $42.00 per ETE
Common Unit.  As a result of these transactions, EPE and its
subsidiaries are considered related parties for financial reporting
purposes.
 
 On
December 23, 2009, Dan L. Duncan and Ralph S. Cunningham were appointed as
directors of our general partner.  Mr. Duncan is Chairman and a
director of EPE Holdings, LLC, the general partner of Enterprise; Chairman and a
director of Enterprise Products GP, LLC, the general partner of Enterprise
Products Partners L.P., or EPD; and Group Co-Chairman of EPCO, Inc. TEPPCO
Partners, L.P., or TEPPCO, is also an affiliate of EPE. Dr. Cunningham is the
President and Chief Executive Officer of EPE Holdings, LLC, the general partner
of Enterprise. These entities and other affiliates of Enterprise are referred to
herein collectively as the “Enterprise Entities.”  Mr. Duncan directly
or indirectly beneficially owns various interests in the Enterprise Entities,
including various general partner interests and approximately 77.1% of the
common units of Enterprise, and approximately 34% of the common units of EPD. On
October 26, 2009, TEPPCO became a wholly owned subsidiary of
Enterprise.
 
 Our
propane operations routinely enter into purchases and sales of propane with
certain of the Enterprise Entities, including purchases under a long-term
contract of Titan to purchase the majority of its propane requirements through
certain of the Enterprise Entities. This agreement was in effect prior to our
acquisition of Titan in 2006 and expires in March 2010 and contains renewal and
extension options.
 
 From time
to time, our natural gas operations purchase from, and sell to, the Enterprise
Entities natural gas and NGLs, in the ordinary course of business. We have a
monthly natural gas storage contract with TEPPCO. Our natural gas operations and
the Enterprise Entities transport natural gas on each other’s pipelines and
share operating expenses on jointly-owned pipelines.
  57
  The
following table presents sales to and purchases from affiliates of
Enterprise.  Amounts reflected below for the year ended August 31,
2007 include transactions beginning on May 7, 2007, the date Enterprise became
an affiliate.  Volumes are presented in thousands of gallons for
propane and NGLs and in billions of Btus for natural gas.
 
 Years Ended December 31,
              
              
              Four
      Months EndedDecember
    31,
              
              
              Year Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Product
              
              Volumes
              
              
              Dollars
              
              
              Volumes
              
              
              Dollars
              
              
              Volumes
              
              
              Dollars
              
              
              Volumes
              
              
              DollarsPropane
      Operations:Sales
              Propane
              
              
              20,370
              
              
              $
              14,046
              
              
              
              13,230
              
              
              $
              19,769
              
              
              
              2,982
              
              
              $
              4,619
              
              
              
              1,470
              
              
              $
              1,725Derivatives
              
              
              -
              
              
              
              5,915
              
              
              
              -
              
              
              
              2,442
              
              
              
              -
              
              
              
              1,857
              
              
              
              -
              
              
              
              22Purchases
              Propane
              
              
              307,525
              
              
              $
              305,148
              
              
              
              318,982
              
              
              $
              472,816
              
              
              
              125,141
              
              
              $
              192,580
              
              
              
              61,660
              
              
              $
              74,688Derivatives
              
              
              -
              
              
              
              38,392
              
              
              
              -
              
              
              
              20,993
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              1Natural
      Gas Operations:Sales
              NGLs
              
              
              477,908
              
              
              $
              374,020
              
              
              
              58,361
              
              
              $
              96,974
              
              
              
              3,240
              
              
              $
              4,726
              
              
              
              464
              
              
              $
              648Natural
      Gas
              
              
              11,532
              
              
              
              44,212
              
              
              
              6,256
              
              
              
              52,205
              
              
              
              2,036
              
              
              
              11,452
              
              
              
              1,495
              
              
              
              9,768Fees
              
              
              -
              
              
              
              (3,899
              )
              
              
              -
              
              
              
              5,093
              
              
              
              -
              
              
              
              610
              
              
              
              -
              
              
              
              -Purchases
              Natural
      GasImbalances
              
              
              176
              
              
              $
              1,164
              
              
              
              3,488
              
              
              $
              (6,485
              )
              
              
              313
              
              
              $
              (911
              )
              
              
              3,120
              
              
              $
              22,677Natural
      Gas
              
              
              10,561
              
              
              
              49,559
              
              
              
              13,457
              
              
              
              120,837
              
              
              
              3,577
              
              
              
              23,341
              
              
              
              1,541
              
              
              
              7,501Fees
              
              
              -
              
              
              
              (2,195
              )
              
              
              -
              
              
              
              876
              
              
              
              -
              
              
              
              311
              
              
              
              -
              
              
              
              -
 
 As of
December 31, 2009 and 2008, Titan had forward mark-to-market derivatives for
approximately 6.1 million and 45.2 million gallons of propane at a fair value
asset of $3.3 million and a fair value liability of $40.1 million, respectively,
with Enterprise.  In addition, as of December 31, 2009, Titan had
forward derivatives accounted for as cash flow hedges of 20.5 million gallons of
propane at a fair value asset of $8.4 million with Enterprise.
 
 The
following table summarizes the related party balances with Enterprise on our
consolidated balance sheets:
 
 December 31,
                2009
              
              
              December 31,
                2008Natural
      Gas Operations:Accounts
      receivable
              
              $
              47,005
              
              
              $
              11,558Accounts
      payable
              
              
              3,518
              
              
              
              567Imbalance
      payable
              
              
              694
              
              
              
              (547
              )Propane
      Operations:Accounts
      receivable
              
              $
              3,386
              
              
              $
              111Accounts
      payable
              
              
              31,642
              
              
              
              33,308
 
 Accounts
receivable from related companies excluding Enterprise consist of the
following:
 
 December 31,
                2009
              
              
              December 31,
                2008MEP
              
              $
              632
              
              
              $
              2,805Energy
      Transfer Technologies, Ltd.
              
              
              -
              
              
              
              16McReynolds
      Energy
              
              
              -
              
              
              
              202Others
              
              
              871
              
              
              
              450Total
      accounts receivable from related companies excluding
      Enterprise
              
              $
              1,503
              
              
              $
              3,473
 
 Effective
August 17, 2009, we acquired 100% of the membership interests of Energy Transfer
Group, L.L.C. (“ETG”), which owns all of the partnership interests of Energy
Transfer Technologies, Ltd. (“ETT”).  ETT provides compression
services to customers engaged in the transportation of natural gas, including
ETP.  The membership interests of ETG were contributed to us by Mr.
Warren and by two entities, one of which is controlled by a director of the
General Partner of ETP’s general partner and the other of which is controlled by
a member of ETP’s management.  In exchange, the former members
acquired the right to receive (in cash or Common Units) future amounts to be
determined based on the terms of the contribution arrangement.  These
contingent amounts are to be determined in 2014 and 2017, and the former members
of ETG may receive payments contingent on the acquired operations performing at
a level above the average return required by ETP for approval of its own growth
projects during the period since acquisition.  In addition, the former
members may be required to make cash payments to us under certain
circumstances.  In connection with this transaction, we assumed
liabilities of $33.5 million and recorded goodwill of $1.7
million.
  58
  Prior to
our acquisition of ETG in August 2009, our natural gas midstream and intrastate
transportation and storage operations secured compression services from
ETT.  The terms of each arrangement to provide compression services
were, in the opinion of independent directors of the General Partner, no more or
less favorable than those available from other providers of compression
services.  During the years ended December 31, 2009 (through the ETG
acquisition date) and 2008, the four months ended December 31, 2007 and the
fiscal year ended August 31, 2007, we made payments totaling $3.4 million, $9.4
million, $0.8 million, and $2.4 million, respectively, to ETG for compression
services provided to and utilized in our natural gas midstream and intrastate
transportation and storage operations.
 
 The
Partnership pays ETP an annual administrative fee of $0.5 million for the
provision of various general and administrative services for ETE’s
benefit.
 
 The Chief
Executive Officer (“CEO”) of ETP’s General Partner, Mr. Kelcy Warren,
voluntarily determined that after 2007, his salary would be reduced to $1.00
plus an amount sufficient to cover his allocated payroll deductions for health
and welfare benefits.  Mr. Warren also declined future cash bonuses
and future equity awards under our 2004 Unit Plan.  We recorded
non-cash compensation expense and an offsetting capital contribution of $1.3
million ($0.5 million in salary and $0.8 million in accrued bonuses) for each of
the years ended December 31, 2009 and 2008 as an estimate of the reasonable
compensation level for the CEO position.
 
 
 15.
              REPORTABLE
      SEGMENTS:
 
 Our
financial statements reflect four reportable segments, which conduct their
business exclusively in the United States of America, as follows:
 
 ·
              natural
      gas operations:
 
 ú
              intrastate
      transportation and storage
 
 ú
              interstate
      transportation
 
 ú
              midstream
 
 ·
              retail
      propane and other retail propane related
  operations
 
 Segments
below the quantitative thresholds are classified as “other”.  The
components of the “other” classification have not met any of the quantitative
thresholds for determining reportable segments.  Management has
included the wholesale propane and natural gas compression services operations
in “other” for all periods presented in this report because such operations are
not material.
 
 Midstream
and intrastate transportation and storage segment revenues and expenses include
intersegment and intrasegment transactions, which are generally based on
transactions made at market-related rates.  Consolidated revenues and
expenses reflect the elimination of all material intercompany
transactions.
 
 The
volumes and results of operations data for fiscal year 2007 do not include the
interstate operations for periods prior to Transwestern’s acquisition on
December 1, 2006.
 
 See
“Business Operations” in Note 1 for a description of the operations of each of
our reportable segments.
 
 We
evaluate the performance of our operating segments based on operating income
exclusive of general partnership selling, general and administrative expenses,
gains (losses) on disposal of assets, interest expense, equity in earnings
(losses) from affiliates and income tax expense (benefit).  Certain
overhead costs relating to a reportable segment have been allocated for purposes
of calculating operating income.  We began allocating administration
expenses from the Partnership to our Operating Companies using the Modified
Massachusetts Formula Calculation (“MMFC”) which is based on factors such as
respective segments’ gross margins, employee costs, and property and
equipment.
  59
  The
expenses subject to allocation are based on estimated amounts and take into
consideration actual expenses from previous months and known
trends.  The difference between the allocation and actual costs is
adjusted in the following month.  The amounts allocated for the
periods presented are as follows:
 
 Years Ended
    December 31,
              
              
              Four Months EndedDecember 31,
              
              
              Year EndedAugust 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Costs
      allocated from ETP to operating subsidiaries:Midstream
      and intrastate transportation and storage operations
              
              $
              15,776
              
              
              $
              19,834
              
              
              $
              6,761
              
              
              $
              11,357Interstate
      operations
              
              
              4,922
              
              
              
              5,750
              
              
              
              2,613
              
              
              
              4,388Retail
      propane and other retail propane related operations
              
              
              12,113
              
              
              
              12,664
              
              
              
              5,992
              
              
              
              10,067Total
              
              $
              32,811
              
              
              $
              38,248
              
              
              $
              15,366
              
              
              $
              25,812Costs
      allocated from operating subsidiaries to ETP:Midstream
      and intrastate transportation and storage operations
              
              $
              6,699
              
              
              $
              10,649
              
              
              $
              2,440
              
              
              $
              5,221Retail
      propane and other retail propane related operations
              
              
              412
              
              
              
              2,428
              
              
              
              850
              
              
              
              2,187Total
              
              $
              7,111
              
              
              $
              13,077
              
              
              $
              3,290
              
              
              $
              7,408
  60
  The
following tables present the financial information by segment for the following
periods:
 
 Four
      MonthsEnded
              
              
              Year
      EndedYears Ended
    December 31,
              
              
              December 31,
              
              
              August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Revenues:Intrastate
      transportation and storageRevenues
      from external customers
              
              $
              1,773,528
              
              
              $
              3,379,424
              
              
              $
              929,357
              
              
              $
              3,085,940Intersegment
      revenues
              
              
              618,016
              
              
              
              2,255,180
              
              
              
              325,044
              
              
              
              829,9922,391,544
              
              
              
              5,634,604
              
              
              
              1,254,401
              
              
              
              3,915,932Interstate
      transportation
              
              
              270,213
              
              
              
              244,224
              
              
              
              76,000
              
              
              
              178,663MidstreamRevenues
      from external customers
              
              
              2,060,451
              
              
              
              4,029,508
              
              
              
              826,835
              
              
              
              2,121,289Intersegment
      revenues
              
              
              380,709
              
              
              
              1,312,885
              
              
              
              339,478
              
              
              
              732,2072,441,160
              
              
              
              5,342,393
              
              
              
              1,166,313
              
              
              
              2,853,496Retail
      propane and other retail propane related - revenues from external
      customers
              
              
              1,292,583
              
              
              
              1,624,010
              
              
              
              511,258
              
              
              
              1,284,867All
      other:Revenues
      from external customers
              
              
              20,520
              
              
              
              16,201
              
              
              
              5,892
              
              
              
              121,278Intersegment
      revenues
              
              
              1,145
              
              
              
              -
              
              
              
              -
              
              
              
              -21,665
              
              
              
              16,201
              
              
              
              5,892
              
              
              
              121,278Eliminations
              
              
              (999,870
              )
              
              
              (3,568,065
              )
              
              
              (664,522
              )
              
              
              (1,562,199
              )Total
      revenues
              
              $
              5,417,295
              
              
              $
              9,293,367
              
              
              $
              2,349,342
              
              
              $
              6,792,037Cost
      of products sold:Intrastate
      transportation and storage
              
              $
              1,393,295
              
              
              $
              4,467,552
              
              
              $
              964,568
              
              
              $
              3,137,712Midstream
              
              
              2,116,279
              
              
              
              4,986,495
              
              
              
              1,043,191
              
              
              
              2,632,187Retail
      propane and other retail propane related
              
              
              596,002
              
              
              
              1,038,722
              
              
              
              325,158
              
              
              
              759,634All
      other
              
              
              16,350
              
              
              
              13,376
              
              
              
              5,259
              
              
              
              110,872Eliminations
              
              
              (999,870
              )
              
              
              (3,568,065
              )
              
              
              (664,522
              )
              
              
              (1,562,199
              )Total
      cost of products sold
              
              $
              3,122,056
              
              
              $
              6,938,080
              
              
              $
              1,673,654
              
              
              $
              5,078,206Depreciation
      and amortization:Intrastate
      transportation and storage
              
              $
              115,884
              
              
              $
              92,979
              
              
              $
              23,429
              
              
              $
              64,423Interstate
      transportation
              
              
              48,297
              
              
              
              37,790
              
              
              
              12,305
              
              
              
              27,972Midstream
              
              
              74,787
              
              
              
              63,287
              
              
              
              14,943
              
              
              
              27,331Retail
      propane and other retail propane related
              
              
              83,476
              
              
              
              79,717
              
              
              
              24,537
              
              
              
              70,833All
      other
              
              
              2,580
              
              
              
              599
              
              
              
              192
              
              
              
              824Total
      depreciation and amortization
              
              $
              325,024
              
              
              $
              274,372
              
              
              $
              75,406
              
              
              $
              191,383Operating
      income (loss):Intrastate
      transportation and storage
              
              $
              618,500
              
              
              $
              710,070
              
              
              $
              169,361
              
              
              $
              479,820Interstate
      transportation
              
              
              138,233
              
              
              
              124,676
              
              
              
              29,657
              
              
              
              95,650Midstream
              
              
              136,790
              
              
              
              162,471
              
              
              
              71,853
              
              
              
              119,233Retail
      propane and other retail propane related
              
              
              229,229
              
              
              
              114,564
              
              
              
              46,747
              
              
              
              124,263All
      other
              
              
              (8,658
              )
              
              
              (2,032
              )
              
              
              (796
              )
              
              
              1,735Selling
      general and administrative expenses not allocated to
    segments
              
              
              (3,696
              )
              
              
              (10,846
              )
              
              
              (171
              )
              
              
              (11,365
              )Total
      operating income
              
              $
              1,110,398
              
              
              $
              1,098,903
              
              
              $
              316,651
              
              
              $
              809,336Other
      items not allocated by segment:Interest
      expense, net of interest capitalized
              
              $
              (468,420
              )
              
              $
              (357,541
              )
              
              $
              (103,375
              )
              
              $
              (279,986
              )Equity
      in earnings (losses) of affiliates
              
              
              20,597
              
              
              
              (165
              )
              
              
              (94
              )
              
              
              5,161Gains
      (losses) on disposal of assets
              
              
              (1,564
              )
              
              
              (1,303
              )
              
              
              14,310
              
              
              
              (6,310
              )Gains
      (losses) on non-hedged interest rate derivatives
              
              
              33,619
              
              
              
              (128,423
              )
              
              
              (28,683
              )
              
              
              29,081Allowance
      for equity funds used during construction
              
              
              10,557
              
              
              
              63,976
              
              
              
              7,276
              
              
              
              4,948Other,
      net
              
              
              1,913
              
              
              
              8,115
              
              
              
              (13,327
              )
              
              
              1,129Income
      tax expense
              
              
              (9,229
              )
              
              
              (3,808
              )
              
              
              (9,949
              )
              
              
              (11,391
              )(412,527
              )
              
              
              (419,149
              )
              
              
              (133,842
              )
              
              
              (257,368
              )Net
      income
              
              $
              697,871
              
              
              $
              679,754
              
              
              $
              182,809
              
              
              $
              551,968
  61
  As of December 31,
              
              
              As
      of August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Total
      assets:Intrastate
      transportation and storage
              
              $
              5,162,164
              
              
              $
              4,911,770
              
              
              $
              4,254,514
              
              
              $
              3,814,391Interstate
      transportation
              
              
              3,313,837
              
              
              
              2,487,078
              
              
              
              1,834,941
              
              
              
              1,653,363Midstream
              
              
              1,653,921
              
              
              
              1,674,028
              
              
              
              1,444,446
              
              
              
              943,760Retail
      propane and other retail propane related
              
              
              1,784,353
              
              
              
              1,810,953
              
              
              
              1,778,426
              
              
              
              1,593,863All
      other
              
              
              246,234
              
              
              
              186,073
              
              
              
              149,767
              
              
              
              177,712Total
              
              $
              12,160,509
              
              
              $
              11,069,902
              
              
              $
              9,462,094
              
              
              $
              8,183,089
 
 
 Years Ended
    December 31,
              
              
              Four
      Months Ended December 31,
              
              
              Year
      Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007Additions
      to property, plant and equipment including acquisitions, net of
      contributions in aid of construction costs (accrual
basis):Intrastate
      transportation and storage
              
              $
              378,494
              
              
              $
              993,886
              
              
              $
              320,965
              
              
              $
              827,859Interstate
      transportation
              
              
              99,341
              
              
              
              720,186
              
              
              
              167,343
              
              
              
              1,345,637Midstream
              
              
              95,081
              
              
              
              267,900
              
              
              
              414,722
              
              
              
              201,646Retail
      propane and other retail propane related
              
              
              62,953
              
              
              
              130,358
              
              
              
              47,553
              
              
              
              65,125All
      other
              
              
              44,911
              
              
              
              3,072
              
              
              
              953
              
              
              
              2,015Total
              
              $
              680,780
              
              
              $
              2,115,402
              
              
              $
              951,536
              
              
              $
              2,442,282
 
 16.
              QUARTERLY FINANCIAL
      DATA (UNAUDITED):
 
 Summarized
unaudited quarterly financial data is presented below.  Earnings per
unit are computed on a stand-alone basis for each quarter and total
year.  HOLP’s and Titan’s businesses are seasonal due to weather
conditions in their service areas.  Propane sales to residential and
commercial customers are affected by winter heating season requirements, which
generally results in higher operating revenues and net income during the period
from October through March of each year and lower operating revenues and either
net losses or lower net income during the period from April through September of
each year.  Sales to commercial and industrial customers are less
weather sensitive.  ETC OLP’s business is also seasonal due to the
operations of ET Fuel System and the HPL System.  We expect margin
related to the HPL System operations to be higher during the periods from
November through March of each year and lower during the periods from April
through October of each year due to the increased demand for natural gas during
the cold weather.  However, we cannot assure that management’s
expectations will be fully realized in the future and in what time period due to
various factors including weather, availability of natural gas in regions in
which we operate, competitive factors in the energy industry, and other
issues.
 
 Quarter Ended2009:
              
              March 31
              
              
              June 30
              
              
              September 30
              
              
              December 31
              
              
              Total YearRevenues
              
              $
              1,629,974
              
              
              $
              1,151,690
              
              
              $
              1,129,849
              
              
              $
              1,505,782
              
              
              $
              5,417,295Gross
      Profit
              
              
              670,835
              
              
              
              525,697
              
              
              
              451,701
              
              
              
              647,006
              
              
              
              2,295,239Operating
      income
              
              
              356,098
              
              
              
              215,031
              
              
              
              173,501
              
              
              
              365,768
              
              
              
              1,110,398Net
      income
              
              
              279,750
              
              
              
              141,758
              
              
              
              34,267
              
              
              
              242,096
              
              
              
              697,871Limited
      Partners’ interest in net income
              
              
              151,067
              
              
              
              104,053
              
              
              
              46,824
              
              
              
              139,159
              
              
              
              441,103Basic
      net income per limited  partner unit
              
              $
              0.68
              
              
              $
              0.47
              
              
              $
              0.21
              
              
              $
              0.62
              
              
              $
              1.98Diluted
      net income per limited  partner unit
              
              $
              0.68
              
              
              $
              0.47
              
              
              $
              0.21
              
              
              $
              0.62
              
              
              $
              1.98
  62
  Quarter Ended2008:
              
              March 31
              
              
              June 30
              
              
              September 30
              
              
              December 31
              
              
              Total YearRevenues
              
              $
              2,639,245
              
              
              $
              2,653,351
              
              
              $
              2,206,090
              
              
              $
              1,794,681
              
              
              $
              9,293,367Gross
      Profit
              
              
              659,527
              
              
              
              529,279
              
              
              
              572,636
              
              
              
              593,845
              
              
              
              2,355,287Operating
      income
              
              
              367,929
              
              
              
              221,940
              
              
              
              256,264
              
              
              
              252,770
              
              
              
              1,098,903Net
      income
              
              
              267,158
              
              
              
              166,818
              
              
              
              185,116
              
              
              
              60,662
              
              
              
              679,754Limited
      Partners’ interest in net income
              
              
              126,313
              
              
              
              120,021
              
              
              
              105,053
              
              
              
              22,496
              
              
              
              373,883Basic
      net income per limited  partner unit
              
              $
              0.57
              
              
              $
              0.54
              
              
              $
              0.47
              
              
              $
              0.10
              
              
              $
              1.68Diluted
      net income per limited  partner unit
              
              $
              0.57
              
              
              $
              0.54
              
              
              $
              0.47
              
              
              $
              0.10
              
              
              $
              1.68
 
 17.
              SUPPLEMENTAL
      INFORMATION:
 
 Following
are the financial statements of the Parent Company, which are included to
provide additional information with respect to the Parent Company's financial
position, results of operations and cash flows on a stand-alone
basis:
  63
  BALANCE
SHEETS
 
 
 December 31,
              
              
              December 31,2009
              
              
              2008ASSETSCURRENT
      ASSETS:Cash
      and cash equivalents
              
              $
              62
              
              
              $
              62Accounts
      receivable from related companies
              
              
              97
              
              
              
              459Other
      current assets
              
              
              1,287
              
              
              
              163Total
      current assets
              
              
              1,446
              
              
              
              684ADVANCES
      TO AND INVESTMENT IN AFFILIATES
              
              
              1,711,928
              
              
              
              1,662,074INTANGIBLES
      AND OTHER ASSETS, net
              
              
              5,574
              
              
              
              8,581Total
      assets
              
              $
              1,718,948
              
              
              $
              1,671,339LIABILITIES AND PARTNERS'
      CAPITALCURRENT
      LIABILITIES:Accounts
      payable
              
              $
              178
              
              
              $
              798Accounts
      payable to affiliates
              
              
              5,024
              
              
              
              3,034Accrued
      interest
              
              
              1,480
              
              
              
              9,222Accrued
      and other current liabilities
              
              
              127
              
              
              
              912Price
      risk management liabilities
              
              
              64,704
              
              
              
              47,453Total
      current liabilities
              
              
              71,513
              
              
              
              61,419LONG-TERM
      DEBT,  less current maturities
              
              
              1,573,951
              
              
              
              1,571,642LONG-TERM
      PRICE RISK MANAGEMENT LIABILITIES
              
              
              73,332
              
              
              
              121,710COMMITMENTS
      AND CONTINGENCIES1,718,796
              
              
              
              1,754,771PARTNERS’
      CAPITAL (DEFICIT):General
      Partner
              
              
              368
              
              
              
              155Limited
      Partner - Common Unitholders (222,898,248 and 222,829,956 units
      authorized, issued and outstanding at December 31, 2009 and 2008,
      respectively
              
              
              53,412
              
              
              
              (15,762
              )Accumulated
      other comprehensive loss
              
              
              (53,628
              )
              
              
              (67,825
              )Total
      partners’ capital (deficit)
              
              
              152
              
              
              
              (83,432
              )Total
      liabilities and partners’ capital (deficit)
              
              $
              1,718,948
              
              
              $
              1,671,339
  64
  STATEMENTS OF
OPERATIONS
 
 
 Years Ended
    December 31,
              
              
              Four
      Months Ended December 31,
              
              
              Year
      Ended August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007SELLING,
      GENERAL AND ADMINISTRATIVE EXPENSES
              
              $
              (4,970
              )
              
              $
              (6,453
              )
              
              $
              (2,875
              )
              
              $
              (8,496
              )OTHER
      INCOME (EXPENSE):Interest
      expense
              
              
              (74,049
              )
              
              
              (91,822
              )
              
              
              (37,071
              )
              
              
              (104,405
              )Equity
      in earnings of affiliates
              
              
              526,383
              
              
              
              551,835
              
              
              
              168,547
              
              
              
              435,247Losses
      on non-hedged interest rate derivatives
              
              
              (5,620
              )
              
              
              (77,435
              )
              
              
              (27,670
              )
              
              
              (1,952
              )Other,
      net
              
              
              79
              
              
              
              (1,056
              )
              
              
              (8,128
              )
              
              
              (405
              )INCOME
      BEFORE INCOME TAXES
              
              
              441,823
              
              
              
              375,069
              
              
              
              92,803
              
              
              
              319,989Income
      tax expense (benefit)
              
              
              (650
              )
              
              
              25
              
              
              
              126
              
              
              
              629NET
      INCOME
              
              
              442,473
              
              
              
              375,044
              
              
              
              92,677
              
              
              
              319,360GENERAL
      PARTNER'S INTEREST IN NET INCOME
              
              
              1,370
              
              
              
              1,161
              
              
              
              287
              
              
              
              1,048LIMITED
      PARTNERS' INTEREST IN NET INCOME
              
              $
              441,103
              
              
              $
              373,883
              
              
              $
              92,390
              
              
              $
              318,312
  65
  STATEMENTS OF CASH
FLOWS
 
 
 Four
      Months
              
              
              YearEnded
              
              
              EndedYears Ended
    December 31,
              
              
              December 31,
              
              
              August 31,2009
              
              
              2008
              
              
              2007
              
              
              2007NET
      CASH FLOWS PROVIDED BY OPERATING ACTIVITIES
              
              $
              468,969
              
              
              $
              436,819
              
              
              $
              77,360
              
              
              $
              239,777CASH
      FLOWS FROM INVESTING ACTIVITIES:Advances
      to and investment in subsidiaries
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (1,200,000
              )Net
      cash used in investing activities
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (1,200,000
              )CASH
      FLOWS FROM FINANCING ACTIVITIES:Proceeds
      from borrowings
              
              
              67,505
              
              
              
              190,533
              
              
              
              1,255
              
              
              
              1,252,662Principal
      payments on debt
              
              
              (65,816
              )
              
              
              (191,464
              )
              
              
              -
              
              
              
              (367,529
              )Equity
      offerings
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              372,434Cash
      distributions to Partners
              
              
              (470,658
              )
              
              
              (435,868
              )
              
              
              (87,174
              )
              
              
              (276,997
              )Debt
      issuance costs
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (11,881
              )Net
      cash provided by (used in) financing activities
              
              
              (468,969
              )
              
              
              (436,799
              )
              
              
              (85,919
              )
              
              
              968,689INCREASE
      (DECREASE) IN CASH AND CASH EQUIVALENTS
              
              
              -
              
              
              
              20
              
              
              
              (8,559
              )
              
              
              8,466CASH
      AND CASH EQUIVALENTS, beginning of period
              
              
              62
              
              
              
              42
              
              
              
              8,601
              
              
              
              135CASH
      AND CASH EQUIVALENTS, end of period
              
              $
              62
              
              
              $
              62
              
              
              $
              42
              
              
              $
              8,601
  66
  18.
              COMPARATIVE
      INFORMATION FOR THE FOUR MONTHS ENDED DECEMBER 31,
      2007:
 
 The
unaudited financial information for the four month period ended December 31,
2006, contained herein is presented for comparative purposes only and does not
contain related financial statement disclosures that would be required with a
complete set of financial statements presented in conformity with accounting
principles generally accepted in the United States of
America.  Certain financial statement amounts have been adjusted due
to the adoption of new accounting standards in 2009.  See Note
2.
  67
  ENERGY TRANSFER EQUITY, L.P.
AND SUBSIDIARIES
 
 CONDENSED CONSOLIDATED
STATEMENTS OF OPERATIONS
 (Dollars
in thousands, except per unit data)
 (unaudited)
 
 Four Months Ended
      December 31,2007
              
              
              2006REVENUES:Natural
      gas operations
              
              $
              1,832,192
              
              
              $
              1,668,667Retail
      propane
              
              
              471,494
              
              
              
              409,821Other
              
              
              45,656
              
              
              
              83,978Total
      revenues
              
              
              2,349,342
              
              
              
              2,162,466COSTS
      AND EXPENSES:Cost
      of products sold - natural gas operations
              
              
              1,343,237
              
              
              
              1,382,473Cost
      of products sold - retail propane
              
              
              315,698
              
              
              
              256,994Cost
      of products sold - other
              
              
              14,719
              
              
              
              50,376Operating
      expenses
              
              
              221,757
              
              
              
              173,365Depreciation
      and amortization
              
              
              75,406
              
              
              
              52,840Selling,
      general and administrative
              
              
              61,874
              
              
              
              43,602Total
      costs and expenses
              
              
              2,032,691
              
              
              
              1,959,650OPERATING
      INCOME
              
              
              316,651
              
              
              
              202,816OTHER
      INCOME (EXPENSE):Interest
      expense, net of interest capitalized
              
              
              (103,375
              )
              
              
              (82,979
              )Equity
      in earnings (losses) of affiliates
              
              
              (94
              )
              
              
              4,743Gain
      on disposal of assets
              
              
              14,310
              
              
              
              2,212Other
      income (expense), net
              
              
              (34,734
              )
              
              
              2,248INCOME
      BEFORE INCOME TAX EXPENSE
              
              
              192,758
              
              
              
              129,040Income
      tax expense
              
              
              9,949
              
              
              
              2,155NET
      INCOME
              
              
              182,809
              
              
              
              126,885LESS:
      NET INCOME ATTRIBUTABLE TONONCONTROLLING
      INTERESTS
              
              
              90,132
              
              
              
              50,204NET
      INCOME ATTRIBUTABLE TO PARTNERS
              
              
              92,677
              
              
              
              76,681GENERAL
      PARTNER'S INTEREST IN NET INCOME
              
              
              287
              
              
              
              290LIMITED
      PARTNERS' INTEREST IN NET INCOME
              
              $
              92,390
              
              
              $
              76,391BASIC
      NET INCOME PER LIMITED PARTNER UNIT
              
              $
              0.41
              
              
              $
              0.45BASIC
      AVERAGE NUMBER OF UNITS OUTSTANDING
              
              
              222,829,916
              
              
              
              170,691,287DILUTED
      NET INCOME PER LIMITED PARTNER UNIT
              
              $
              0.41
              
              
              $
              0.45DILUTED
      AVERAGE NUMBER OF UNITS  OUTSTANDING
              
              
              222,829,916
              
              
              
              170,691,287
  68
  ENERGY TRANSFER EQUITY, L.P.
AND SUBSIDIARIES
 
 CONDENSED CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
 (Dollars
in thousands)
 (unaudited)
 
 Four Months Ended
      December 31,2007
              
              
              2006Net
      income
              
              $
              182,809
              
              
              $
              126,885Other
      comprehensive income (loss), net of tax:Reclassification
      to earnings of gains and losses on derivative instruments accounted for as
      cash flow hedges
              
              
              (17,970
              )
              
              
              (23,698
              )Change
      in value of derivative instruments accounted for as cash flow
      hedges
              
              
              (2,221
              )
              
              
              158,916Change
      in value of available-for-sale securities
              
              
              (98
              )
              
              
              (401
              )(20,289
              )
              
              
              134,817Comprehensive
      income
              
              
              162,520
              
              
              
              261,702Less:
      Comprehensive income attributable to non-controlling
    interest
              
              
              92,832
              
              
              
              117,677Comprehensive
      income attributable to partners
              
              $
              69,688
              
              
              $
              144,025
  69
  ENERGY TRANSFER EQUITY, L.P.
AND SUBSIDIARIES
 
 CONDENSED CONSOLIDATED
STATEMENTS OF CASH FLOWS
 (Dollars
in thousands)
 (unaudited)
 
 Four Months Ended
      December 31,2007
              
              
              2006NET
      CASH FLOWS PROVIDED BY OPERATING ACTIVITIES:Net
      income
              
              $
              182,809
              
              
              $
              126,885Reconciliation
      of net income to net cash provided by operating
activities:Depreciation
      and amortization
              
              
              75,406
              
              
              
              52,840Amortization
      in interest expense
              
              
              2,441
              
              
              
              1,697Provision
      for loss on accounts receivable
              
              
              544
              
              
              
              563Gain
      on disposal of assets
              
              
              (14,310
              )
              
              
              (2,212
              )Non-cash
      unit-based compensation expense
              
              
              8,137
              
              
              
              4,385Non-cash
      executive compensation
              
              
              442
              
              
              
              -Distributions
      in excess of (less than) equity in earnings of affiliates,
    net
              
              
              4,448
              
              
              
              (4,742
              )Deferred
      income taxes
              
              
              37
              
              
              
              (3,199
              )Other
      non-cash
              
              
              (2,069
              )
              
              
              -Net
      change in operating assets and liabilities, net of
      acquisitions
              
              
              (49,250
              )
              
              
              218,586Net
      cash provided by operating activities
              
              
              208,635
              
              
              
              394,803CASH
      FLOWS FROM INVESTING ACTIVITIES:Cash
      paid for acquisitions, net of cash acquired
              
              
              (337,092
              )
              
              
              (67,089
              )Capital
      expenditures
              
              
              (651,228
              )
              
              
              (336,473
              )Contributions
      in aid of construction costs
              
              
              3,493
              
              
              
              4,984Advances
      to and investment in affiliates
              
              
              (32,594
              )
              
              
              (953,247
              )Proceeds
      from the sale of assets
              
              
              21,478
              
              
              
              7,644Net
      cash used in investing activities
              
              
              (995,943
              )
              
              
              (1,344,181
              )CASH
      FLOWS FROM FINANCING ACTIVITIES:Proceeds
      from borrowings
              
              
              1,742,802
              
              
              
              2,911,149Principal
      payments on debt
              
              
              (1,062,272
              )
              
              
              (1,941,610
              )Subsidiary
      equity offering net of issue costs
              
              
              234,887
              
              
              
              -Net
      proceeds from issuance of Common Units
              
              
              -
              
              
              
              213,287Distributions
      to Partners
              
              
              (87,174
              )
              
              
              (39,867
              )Debt
      issuance costs
              
              
              (211
              )
              
              
              (21,302
              )Distributions
      to noncontrolling interests
              
              
              (61,517
              )
              
              
              (75,868
              )Net
      cash provided by financing activities
              
              
              766,515
              
              
              
              1,045,789INCREASE
      IN CASH AND CASH EQUIVALENTS
              
              
              (20,793
              )
              
              
              96,411CASH
      AND CASH EQUIVALENTS, beginning of period
              
              
              77,350
              
              
              
              26,204CASH
      AND CASH EQUIVALENTS, end of period
              
              $
              56,557
              
              
              $
              122,615NON-CASH
      INVESTING AND FINANCING ACTIVITIESSUPPLEMENTAL
      CASH FLOW INFORMATION:NON-CASH
      INVESTING ACTIVITIES:Capital
      expenditures accrued
              
              $
              87,622
              
              
              $
              13,294Gain
      from subsidiary issuance of common units (recorded in partners'
      capital)
              
              $
              48,932
              
              
              $
              -NON-CASH
      FINANCING ACTIVITIES:Long-term
      debt assumed and non-compete agreement notes payable issued in
      acquisitions
              
              $
              3,896
              
              
              $
              532,631Issuance
      of common units in connection with certain acquisitions
              
              $
              1,400
              
              
              $
              -SUPPLEMENTAL
      DISCLOSURE OF CASH FLOW INFORMATION:Cash
      paid during the period for interest, net of interest
      capitalized
              
              $
              79,084
              
              
              $
              50,480Cash
      paid during the period for  income taxes
              
              $
              9,135
              
              
              $
              6,197
   70